In situ thermal recovery from a relatively permeable formation with backproduction through a heater wellbore

ABSTRACT

A method for treating a relatively permeable formation containing heavy hydrocarbons in situ may include providing heat from one or more heat sources to a portion of the formation. The heat may be allowed to transfer from the heat sources to a selected section of the formation. The transferred heat may pyrolyze at least some hydrocarbons within the selected section. A temperature proximate a selected portion of a heater well may be selectively limited to inhibit coke formation at or near the selected portion. A mixture of at least some hydrocarbons may be produced through the selected portion of the heater well.

PRIORITY CLAIM

[0001] This application claims priority to Provisional PatentApplication No. 60/286,156 entitled “IN SITU THERMAL PROCESSING OF HEAVYOIL WITHIN A PERMEABLE FORMATION” filed on Apr. 24, 2001 and toProvisional Patent Application No. 60/338,789 entitled “IN SITU THERMALPROCESSING OF A RELATIVELY PERMEABLE FORMATION CONTAINING HEAVYHYDROCARBONS” filed on Oct. 24, 2001.

BACKGROUND OF THE INVENTION

[0002] 1. Field of the Invention

[0003] The present invention relates generally to methods and systemsfor production of hydrocarbons, hydrogen, and/or other products fromvarious relatively permeable formations containing heavy hydrocarbons.Certain embodiments relate to in situ conversion of hydrocarbons toproduce hydrocarbons, hydrogen, and/or novel product streams fromunderground relatively permeable formations.

[0004] 2. Description of Related Art

[0005] Hydrocarbons obtained from subterranean (e.g., sedimentary)formations are often used as energy resources, as feedstocks, and asconsumer products. Concerns over depletion of available hydrocarbonresources and over declining overall quality of produced hydrocarbonshave led to development of processes for more efficient recovery,processing and/or use of available hydrocarbon resources. In situprocesses may be used to remove hydrocarbon materials from subterraneanformations. Chemical and/or physical properties of hydrocarbon materialwithin a subterranean formation may need to be changed to allowhydrocarbon material to be more easily removed from the subterraneanformation. The chemical and physical changes may include in situreactions that produce removable fluids, composition changes, solubilitychanges, density changes, phase changes, and/or viscosity changes of thehydrocarbon material within the formation. A fluid may be, but is notlimited to, a gas, a liquid, an emulsion, a slurry, and/or a stream ofsolid particles that has flow characteristics similar to liquid flow.

[0006] Examples of in situ processes utilizing downhole heaters areillustrated in U.S. Pat. Nos. 2,634,961 to Ljungstrom, 2,732,195 toLjungstrom, 2,780,450 to Ljungstrom, 2,789,805 to Ljungstrom, 2,923,535to Ljungstrom, and 4,886,118 to Van Meurs et al., each of which isincorporated by reference as if fully set forth herein.

[0007] Application of heat to oil shale formations is described in U.S.Pat. Nos. 2,923,535 to Ljungstrom and 4,886,118 to Van Meurs et al. Heatmay be applied to the oil shale formation to pyrolyze kerogen within theoil shale formation. The heat may also fracture the formation toincrease permeability of the formation. The increased permeability mayallow formation fluid to travel to a production well where the fluid isremoved from the oil shale formation. In some processes disclosed byLjungstrom, for example, an oxygen containing gaseous medium isintroduced to a permeable stratum, preferably while still hot from apreheating step, to initiate combustion.

[0008] A heat source may be used to heat a subterranean formation.Electric heaters may be used to heat the subterranean formation byradiation and/or conduction. An electric heater may resistively heat anelement. U.S. Pat. No. 2,548,360 to Germain, which is incorporated byreference as if fully set forth herein, describes an electric heatingelement placed within a viscous oil within a wellbore. The heaterelement heats and thins the oil to allow the oil to be pumped from thewellbore. U.S. Pat. No. 4,716,960 to Eastlund et al., which isincorporated by reference as if fully set forth herein, describeselectrically heating tubing of a petroleum well by passing a relativelylow voltage current through the tubing to prevent formation of solids.U.S. Pat. No. 5,065,818 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electric heatingelement that is cemented into a well borehole without a casingsurrounding the heating element.

[0009] U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporatedby reference as if fully set forth herein, describes an electric heatingelement that is positioned within a casing. The heating elementgenerates radiant energy that heats the casing. A granular solid fillmaterial may be placed between the casing and the formation. The casingmay conductively heat the fill material, which in turn conductivelyheats the formation.

[0010] U.S. Pat. No. 4,570,715 to Van Meurs et al., which isincorporated by reference as if fully set forth herein, describes anelectric heating element. The heating element has an electricallyconductive core, a surrounding layer of insulating material, and asurrounding metallic sheath. The conductive core may have a relativelylow resistance at high temperatures. The insulating material may haveelectrical resistance, compressive strength, and heat conductivityproperties that are relatively high at high temperatures. The insulatinglayer may inhibit arcing from the core to the metallic sheath. Themetallic sheath may have tensile strength and creep resistanceproperties that are relatively high at high temperatures.

[0011] U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement having a copper-nickel alloy core.

[0012] Combustion of a fuel may be used to heat a formation. Combustinga fuel to heat a formation may be more economical than using electricityto heat a formation. Several different types of heaters may use fuelcombustion as a heat source that heats a formation. The combustion maytake place in the formation, in a well, and/or near the surface.Combustion in the formation may be a fireflood. An oxidizer may bepumped into the formation. The oxidizer may be ignited to advance a firefront towards a production well. Oxidizer pumped into the formation mayflow through the formation along fracture lines in the formation.Ignition of the oxidizer may not result in the fire front flowinguniformly through the formation.

[0013] A flameless combustor may be used to combust a fuel within awell. U.S. Pat. Nos. 5,255,742 to Mikus, 5,404,952 to Vinegar et al.,5,862,858 to Wellington et al., and 5,899,269 to Wellington et al.,which are incorporated by reference as if fully set forth herein,describe flameless combustors. Flameless combustion may be accomplishedby preheating a fuel and combustion air to a temperature above anauto-ignition temperature of the mixture. The fuel and combustion airmaybe mixed in a heating zone to combust. In the heating zone of theflameless combustor, a catalytic surface may be provided to lower theauto-ignition temperature of the fuel and air mixture.

[0014] Heat may be supplied to a formation from a surface heater. Thesurface heater may produce combustion gases that are circulated throughwellbores to heat the formation. Alternately, a surface burner may beused to heat a heat transfer fluid that is passed through a wellbore toheat the formation. Examples of fired heaters, or surface burners thatmay be used to heat a subterranean formation, are illustrated in U.S.Pat. Nos. 6,056,057 to Vinegar et al. and 6,079,499 to Mikus et al.,which are both incorporated by reference as if fully set forth herein.

[0015] Synthesis gas may be produced in reactors or in situ within asubterranean formation. Synthesis gas may be produced within a reactorby partially oxidizing methane with oxygen. In situ production ofsynthesis gas may be economically desirable to avoid the expense ofbuilding, operating, and maintaining a surface synthesis gas productionfacility. U.S. Pat. No. 4,250,230 to Terry, which is incorporated byreference as if fully set forth herein, describes a system for in situgasification of coal. A subterranean coal seam is burned from a firstwell towards a production well. Methane, hydrocarbons, H₂, CO, and otherfluids may be removed from the formation through the production well.The H₂ and CO may be separated from the remaining fluid. The H₂ and COmay be sent to fuel cells to generate electricity.

[0016] U.S. Pat. No. 4,057,293 to Garrett, which is incorporated byreference as if fully set forth herein, discloses a process forproducing synthesis gas. A portion of a rubble pile is burned to heatthe rubble pile to a temperature that generates liquid and gaseoushydrocarbons by pyrolysis. After pyrolysis, the rubble is furtherheated, and steam or steam and air are introduced to the rubble pile togenerate synthesis gas.

[0017] U.S. Pat. No. 5,554,453 to Steinfeld et al., which isincorporated by reference as if fully set forth herein, describes an exsitu coal gasifier that supplies fuel gas to a fuel cell. The fuel cellproduces electricity. A catalytic burner is used to burn exhaust gasfrom the fuel cell with an oxidant gas to generate heat in the gasifier.

[0018] Carbon dioxide may be produced from combustion of fuel and frommany chemical processes. Carbon dioxide may be used for variouspurposes, such as, but not limited to, a feed stream for a dry iceproduction facility, supercritical fluid in a low temperaturesupercritical fluid process, a flooding agent for coal beddemethanation, and a flooding agent for enhanced oil recovery. Althoughsome carbon dioxide is productively used, many tons of carbon dioxideare vented to the atmosphere.

[0019] Large deposits of heavy hydrocarbons (e.g., heavy oil and/or tar)contained within relatively permeable formations (e.g., in tar sands)are found in North America, South America, Africa, and Asia. Tar can besurface-mined and upgraded to lighter hydrocarbons such as crude oil,naphtha, kerosene, and/or gas oil. Tar sand deposits may, for example,first be mined. Surface milling processes may further separate thebitumen from sand. The separated bitumen may be converted to lighthydrocarbons using conventional refinery methods. Mining and upgradingtar sand is usually substantially more expensive than producing lighterhydrocarbons from conventional oil reservoirs.

[0020] U.S. Pat. Nos. 5,340,467 to Gregoli et al. and 5,316,467 toGregoli et al., which are incorporated by reference as if fully setforth herein, describe adding water and a chemical additive to tar sandto form a slurry. The slurry may be separated into hydrocarbons andwater.

[0021] U.S. Pat. No. 4,409,090 to Hanson et al., which is incorporatedby reference as if fully set forth herein, describes physicallyseparating tar sand into a bitumen-rich concentrate that may have someremaining sand. The bitumen-rich concentrate may be further separatedfrom sand in a fluidized bed.

[0022] U.S. Pat. Nos. 5,985,138 to Humphreys and 5,968,349 to Duyvesteynet al., which are incorporated by reference as if fully set forthherein, describe mining tar sand and physically separating bitumen fromthe tar sand. Further processing of bitumen in surface facilities mayupgrade oil produced from bitumen.

[0023] In situ production of hydrocarbons from tar sand may beaccomplished by heating and/or injecting a gas into the formation. U.S.Pat. Nos. 5,211,230 to Ostapovich et al. and 5,339,897 to Leaute, whichare incorporated by reference as if fully set forth herein, describe ahorizontal production well located in an oil-beating reservoir. Avertical conduit may be used to inject an oxidant gas into the reservoirfor in situ combustion.

[0024] U.S. Pat. No. 2,780,450 to Ljungstrom describes heatingbituminous geological formations in situ to convert or crack a liquidtar-like substance into oils and gases.

[0025] U.S. Pat. No. 4,597,441 to Ware et al., which is incorporated byreference as if fully set forth herein, describes contacting oil, heat,and hydrogen simultaneously in a reservoir. Hydrogenation may enhancerecovery of oil from the reservoir.

[0026] U.S. Pat. No. 5,046,559 to Glandt and 5,060,726 to Glandt et al.,which are incorporated by reference as if fully set forth herein,describe preheating a portion of a tar sand formation between aninjector well and a producer well. Steam may be injected from theinjector well into the formation to produce hydrocarbons at the producerwell.

[0027] As outlined above, there has been a significant amount of effortto develop methods and systems to economically produce hydrocarbons,hydrogen, and/or other products from relatively permeable formations. Atpresent, however, there are still many relatively permeable formationsfrom which hydrocarbons, hydrogen, and/or other products cannot beeconomically produced. Thus, there is still a need for improved methodsand systems for production of hydrocarbons, hydrogen, and/or otherproducts from various relatively permeable formations.

SUMMARY OF THE INVENTION

[0028] In an embodiment, hydrocarbons within a relatively permeableformation may be converted in situ within the formation to yield amixture of relatively high quality hydrocarbon products, hydrogen,and/or other products. One or more heat sources may be used to heat aportion of the relatively permeable formation to temperatures that allowpyrolysis of the hydrocarbons. Hydrocarbons, hydrogen, and otherformation fluids may be removed from the formation through one or moreproduction wells. In some embodiments, formation fluids may be removedin a vapor phase. In other embodiments, formation fluids may be removedin liquid and vapor phases or in a liquid phase. Temperature andpressure in at least a portion of the formation may be controlled duringpyrolysis to yield improved products from the formation.

[0029] In an embodiment, one or more heat sources may be installed intoa formation to heat the formation. Heat sources may be installed bydrilling openings (well bores) into the formation. In some embodiments,openings may be formed in the formation using a drill with a steerablemotor and an accelerometer. Alternatively, an opening may be formed intothe formation by geosteered drilling. Alternately, an opening may beformed into the formation by sonic drilling.

[0030] One or more heat sources may be disposed within the opening suchthat the heat sources transfer heat to the formation. For example, aheat source may be placed in an open wellbore in the formation. Heat mayconductively and radiatively transfer from the heat source to theformation. Alternatively, a heat source may be placed within a heaterwell that may be packed with gravel, sand, and/or cement. The cement maybe a refractory cement.

[0031] In some embodiments, one or more heat sources may be placed in apattern within the formation. For example, in one embodiment, an in situconversion process for hydrocarbons may include heating at least aportion of a relatively permeable formation with an array of heatsources disposed within the formation. In some embodiments, the array ofheat sources can be positioned substantially equidistant from aproduction well. Certain patterns (e.g., triangular arrays, hexagonalarrays, or other array patterns) may be more desirable for specificapplications. In addition, the array of heat sources may be disposedsuch that a distance between each heat source may be less than about 70feet (21 m). In addition, the in situ conversion process forhydrocarbons may include heating at least a portion of the formationwith heat sources disposed substantially parallel to a boundary of thehydrocarbons. Regardless of the arrangement of or distance between theheat sources, in certain embodiments, a ratio of heat sources toproduction wells disposed within a formation may be greater than about3, 5, 8, 10, 20, or more.

[0032] Certain embodiments may also include allowing heat to transferfrom one or more of the heat sources to a selected section of the heatedportion. In an embodiment, the selected section may be disposed betweenone or more heat sources. For example, the in situ conversion processmay also include allowing heat to transfer from one or more heat sourcesto a selected section of the formation such that heat from one or moreof the heat sources pyrolyzes at least some hydrocarbons within theselected section. The in situ conversion process may include heating atleast a portion of a relatively permeable formation above a pyrolyzationtemperature of hydrocarbons in the formation. For example, apyrolyzation temperature may include a temperature of at least about270° C. Heat may be allowed to transfer from one or more of the heatsources to the selected section substantially by conduction.

[0033] One or more heat sources may be located within the formation suchthat superposition of heat produced from one or more heat sources mayoccur. Superposition of heat may increase a temperature of the selectedsection to a temperature sufficient for pyrolysis of at least some ofthe hydrocarbons within the selected section. Superposition of heat mayvary depending on, for example, a spacing between heat sources. Thespacing between heat sources may be selected to optimize heating of thesection selected for treatment. Therefore, hydrocarbons may be pyrolyzedwithin a larger area of the portion. Spacing between heat sources may beselected to increase the effectiveness of the heat sources, therebyincreasing the economic viability of a selected in situ conversionprocess for hydrocarbons. Superposition of heat tends to increase theuniformity of heat distribution in the section of the formation selectedfor treatment.

[0034] Various systems and methods may be used to provide heat sources.In an embodiment, a natural distributed combustor system and method mayheat at least a portion of a relatively permeable formation. The systemand method may first include heating a first portion of the formation toa temperature sufficient to support oxidation of at least some of thehydrocarbons therein. One or more conduits may be disposed within one ormore openings. One or more of the conduits may provide an oxidizingfluid from an oxidizing fluid source into an opening in the formation.The oxidizing fluid may oxidize at least a portion of the hydrocarbonsat a reaction zone within the formation. Oxidation may generate heat atthe reaction zone. The generated heat may transfer from the reactionzone to a pyrolysis zone in the formation. The heat may transfer byconduction, radiation, and/or convection. A heated portion of theformation may include the reaction zone and the pyrolysis zone. Theheated portion may also be located adjacent to the opening. One or moreof the conduits may remove one or more oxidation products from thereaction zone and/or the opening in the formation. Alternatively,additional conduits may remove one or more oxidation products from thereaction zone and/or formation.

[0035] In certain embodiments, the flow of oxidizing fluid may becontrolled along at least a portion of the length of the reaction zone.In some embodiments, hydrogen may be allowed to transfer into thereaction zone.

[0036] In an embodiment, a system and a method may include an opening inthe formation extending from a first location on the surface of theearth to a second location on the surface of the earth. For example, theopening may be substantially U-shaped. Heat sources may be placed withinthe opening to provide heat to at least a portion of the formation.

[0037] A conduit may be positioned in the opening extending from thefirst location to the second location. In an embodiment, a heat sourcemay be positioned proximate and/or in the conduit to provide heat to theconduit. Transfer of the heat through the conduit may provide heat to aselected section of the formation. In some embodiments, an additionalheater may be placed in an additional conduit to provide heat to theselected section of the formation through the additional conduit.

[0038] In some embodiments, an annulus is formed between a wall of theopening and a wall of the conduit placed within the opening extendingfrom the first location to the second location. A heat source may beplace proximate and/or in the annulus to provide heat to a portion theopening. The provided heat may transfer through the annulus to aselected section of the formation.

[0039] In an embodiment, a system and method for heating a relativelypermeable formation may include one or more insulated conductorsdisposed in one or more openings in the formation. The openings may beuncased. Alternatively, the openings may include a casing. As such, theinsulated conductors may provide conductive, radiant, or convective heatto at least a portion of the formation. In addition, the system andmethod may allow heat to transfer from the insulated conductor to asection of the formation. In some embodiments, the insulated conductormay include a copper-nickel alloy. In some embodiments, the insulatedconductor may be electrically coupled to two additional insulatedconductors in a 3-phase Y configuration.

[0040] An embodiment of a system and method for heating a relativelypermeable formation may include a conductor placed within a conduit(e.g., a conductor-in-conduit heat source). The conduit may be disposedwithin the opening. An electric current may be applied to the conductorto provide heat to a portion of the formation. The system may allow heatto transfer from the conductor to a section of the formation during use.In some embodiments, an oxidizing fluid source may be placed proximatean opening in the formation extending from the first location on theearth's surface to the second location on the earth's surface. Theoxidizing fluid source may provide oxidizing fluid to a conduit in theopening. The oxidizing fluid may transfer from the conduit to a reactionzone in the formation. In an embodiment, an electrical current may beprovided to the conduit to heat a portion of the conduit. The heat maytransfer to the reaction zone in the relatively permeable formation.Oxidizing fluid may then be provided to the conduit. The oxidizing fluidmay oxidize hydrocarbons in the reaction zone, thereby generating heat.The generated heat may transfer to a pyrolysis zone and the transferredheat may pyrolyze hydrocarbons within the pyrolysis zone.

[0041] In some embodiments, an insulation layer may be coupled to aportion of the conductor. The insulation layer may electrically insulateat least a portion of the conductor from the conduit during use.

[0042] In an embodiment, a conductor-in-conduit heat source having adesired length may be assembled. A conductor may be placed within theconduit to form the conductor-in-conduit heat source. Two or moreconductor-in-conduit heat sources may be coupled together to form a heatsource having the desired length. The conductors of theconductor-in-conduit heat sources may be electrically coupled together.In addition, the conduits may be electrically coupled together. Adesired length of the conductor-in-conduit may be placed in an openingin the relatively permeable formation. In some embodiments, individualsections of the conductor-in-conduit heat source may be coupled usingshielded active gas welding.

[0043] In some embodiments, a centralizer may be used to inhibitmovement of the conductor within the conduit. A centralizer may beplaced on the conductor as a heat source is made. In certainembodiments, a protrusion may be placed on the conductor to maintain thelocation of a centralizer.

[0044] In certain embodiments, a heat source of a desired length may beassembled proximate the relatively permeable formation. The assembledheat sources may then be coiled. The heat source may be placed in therelatively permeable formation by uncoiling the heat source into theopening in the relatively permeable formation.

[0045] In certain embodiments, portions of the conductors may include anelectrically conductive material. Use of the electrically conductivematerial on a portion (e.g., in the overburden portion) of the conductormay lower an electrical resistance of the conductor.

[0046] A conductor placed in a conduit may be treated to increase theemissivity of the conductor, in some embodiments. The emissivity of theconductor may be increased by roughening at least a portion of thesurface of the conductor. In certain embodiments, the conductor may betreated to increase the emissivity prior to being placed within theconduit. In some embodiments, the conduit may be treated to increase theemissivity of the conduit.

[0047] In an embodiment, a system and method may include one or moreelongated members disposed in an opening in the formation. Each of theelongated members may provide heat to at least a portion of theformation. One or more conduits may be disposed in the opening. One ormore of the conduits may provide an oxidizing fluid from an oxidizingfluid source into the opening. In certain embodiments, the oxidizingfluid may inhibit carbon deposition on or proximate the elongatedmember.

[0048] In certain embodiments, an expansion mechanism may be coupled toa heat source. The expansion mechanism may allow the heat source to moveduring use. For example, the expansion mechanism may allow for theexpansion of the heat source during use.

[0049] In one embodiment, an in situ method and system for heating arelatively permeable formation may include providing oxidizing fluid toa first oxidizer placed in an opening in the formation. Fuel may beprovided to the first oxidizer and at least some fuel may be oxidized inthe first oxidizer. Oxidizing fluid may be provided to a second oxidizerplaced in the opening in the formation. Fuel may be provided to thesecond oxidizer and at least some fuel may be oxidized in the secondoxidizer. Heat from oxidation of fuel may be allowed to transfer to aportion of the formation.

[0050] An opening in a relatively permeable formation may include afirst elongated portion, a second elongated portion, and a thirdelongated portion. Certain embodiments of a method and system forheating a relatively permeable formation may include providing heat froma first heater placed in the second elongated portion. The secondelongated portion may diverge from the first elongated portion in afirst direction. The third elongated portion may diverge from the firstelongated portion in a second direction. The first direction may besubstantially different than the second direction. Heat may be providedfrom a second heater placed in the third elongated portion of theopening in the formation. Heat from the first heater and the secondheater may be allowed to transfer to a portion of the formation.

[0051] An embodiment of a method and system for heating a relativelypermeable formation may include providing oxidizing fluid to a firstoxidizer placed in an opening in the formation. Fuel may be provided tothe first oxidizer and at least some fuel may be oxidized in the firstoxidizer. The method may further include allowing heat from oxidation offuel to transfer to a portion of the formation and allowing heat totransfer from a heater placed in the opening to a portion of theformation.

[0052] In an embodiment, a system and method for heating a relativelypermeable formation may include oxidizing a fuel fluid in a heater. Themethod may further include providing at least a portion of the oxidizedfuel fluid into a conduit disposed in an opening in the formation. Inaddition, additional heat may be transferred from an electric heaterdisposed in the opening to the section of the formation. Heat may beallowed to transfer uniformly along a length of the opening.

[0053] Energy input costs may be reduced in some embodiments of systemsand methods described above. For example, an energy input cost may bereduced by heating a portion of a relatively permeable formation byoxidation in combination with heating the portion of the formation by anelectric heater. The electric heater may be turned down and/or off whenthe oxidation reaction begins to provide sufficient heat to theformation. Electrical energy costs associated with heating at least aportion of a formation with an electric heater may be reduced. Thus, amore economical process may be provided for heating a relativelypermeable formation in comparison to heating by a conventional method.In addition, the oxidation reaction may be propagated slowly through agreater portion of the formation such that fewer heat sources may berequired to heat such a greater portion in comparison to heating by aconventional method.

[0054] Certain embodiments as described herein may provide a lower costsystem and method for heating a relatively permeable formation. Forexample, certain embodiments may more uniformly transfer heat along alength of a heater. Such a length of a heater may be greater than about300 m or possibly greater than about 600 m. In addition, in certainembodiments, heat may be provided to the formation more efficiently byradiation. Furthermore, certain embodiments of systems may have asubstantially longer lifetime than presently available systems.

[0055] In an embodiment, an in situ conversion system and method forhydrocarbons may include maintaining a portion of the formation in asubstantially unheated condition. The portion may provide structuralstrength to the formation and/or confinement/isolation to certainregions of the formation. A processed relatively permeable formation mayhave alternating heated and substantially unheated portions arranged ina pattern that may, in some embodiments, resemble a checkerboardpattern, or a pattern of alternating areas (e.g., strips) of heated andunheated portions.

[0056] In an embodiment, a heat source may advantageously heat onlyalong a selected portion or selected portions of a length of the heater.For example, a formation may include several hydrocarbon containinglayers. One or more of the hydrocarbon containing layers may beseparated by layers containing little or no hydrocarbons. A heat sourcemay include several discrete high heating zones that may be separated bylow heating zones. The high heating zones may be disposed proximatehydrocarbon containing layers such that the layers may be heated. Thelow heating zones may be disposed proximate layers containing little orno hydrocarbons such that the layers may not be substantially heated.For example, an electric heater may include one or more low resistanceheater sections and one or more high resistance heater sections. Lowresistance heater sections of the electric heater may be disposed inand/or proximate layers containing little or no hydrocarbons. Inaddition, high resistance heater sections of the electric heater may bedisposed proximate hydrocarbon containing layers. In an additionalexample, a fueled heater (e.g., surface burner) may include insulatedsections. Insulated sections of the fueled heater may be placedproximate or adjacent to layers containing little or no hydrocarbons.Alternately, a heater with distributed air and/or fuel may be configuredsuch that little or no fuel may be combusted proximate or adjacent tolayers containing little or no hydrocarbons. Such a fueled heater mayinclude flameless combustors and natural distributed combustors. Incertain embodiments, the permeability of a relatively permeableformation may vary within the formation. For example, a first sectionmay have a lower permeability than a second section. In an embodiment,heat may be provided to the formation to pyrolyze hydrocarbons withinthe lower permeability first section. Pyrolysis products may be producedfrom the higher permeability second section in a mixture ofhydrocarbons.

[0057] In an embodiment, a heating rate of the formation may be slowlyraised through the pyrolysis temperature range. For example, an in situconversion process for hydrocarbons may include heating at least aportion of a relatively permeable formation to raise an averagetemperature of the portion above about 270° C. by a rate less than aselected amount (e.g., about 10° C., 5° C., 3° C., 1° C., 0.5° C., or0.1° C.) per day. In a further embodiment, the portion may be heatedsuch that an average temperature of the selected section may be lessthan about 375° C. or, in some embodiments, less than about 400° C.

[0058] In an embodiment, a temperature of the portion may be monitoredthrough a test well disposed in a formation. For example, the test wellmay be positioned in a formation between a first heat source and asecond heat source. Certain systems and methods may include controllingthe heat from the first heat source and/or the second heat source toraise the monitored temperature at the test well at a rate of less thanabout a selected amount per day. In addition or alternatively, atemperature of the portion may be monitored at a production well. An insitu conversion process for hydrocarbons may include controlling theheat from the first heat source and/or the second heat source to raisethe monitored temperature at the production well at a rate of less thana selected amount per day.

[0059] An embodiment of an in situ method of measuring a temperaturewithin a wellbore may include providing a pressure wave from a pressurewave source into the wellbore. The wellbore may include a plurality ofdiscontinuities along a length of the wellbore. The method furtherincludes measuring a reflection signal of the pressure wave and usingthe reflection signal to assess at least one temperature between atleast two discontinuities.

[0060] Certain embodiments may include heating a selected volume of arelatively permeable formation. Heat may be provided to the selectedvolume by providing power to one or more heat sources. Power may bedefined as heating energy per day provided to the selected volume. Apower (Pwr) required to generate a heating rate (h, in units of, forexample, ° C./day) in a selected volume (V) of a relatively permeableformation may be determined by EQN. 1:

Pwr=h*V*C _(v)*ρ_(B).  (1)

[0061] In this equation, an average heat capacity of the formation(C_(v)) and an average bulk density of the formation (ρ_(B)) may beestimated or determined using one or more samples taken from therelatively permeable formation.

[0062] Certain embodiments may include raising and maintaining apressure in a relatively permeable formation. Pressure may be, forexample, controlled within a range of about 2 bars absolute to about 20bars absolute. For example, the process may include controlling apressure within a majority of a selected section of a heated portion ofthe formation. The controlled pressure may be above about 2 barsabsolute during pyrolysis. In an alternate embodiment, an in situconversion process for hydrocarbons may include raising and maintainingthe pressure in the formation within a range of about 20 bars absoluteto about 36 bars absolute.

[0063] In an embodiment, compositions and properties of formation fluidsproduced by an in situ conversion process for hydrocarbons may varydepending on, for example, conditions within a relatively permeableformation.

[0064] Certain embodiments may include controlling the heat provided toat least a portion of the formation such that production of lessdesirable products in the portion may be inhibited. Controlling the heatprovided to at least a portion of the formation may also increase theuniformity of permeability within the formation. For example,controlling the heating of the formation to inhibit production of lessdesirable products may, in some embodiments, include controlling theheating rate to less than a selected amount (e.g., 10° C., 5° C., 3° C.,1° C., 0.5° C., or 0.1° C.) per day.

[0065] Controlling pressure, heat and/or heating rates of a selectedsection in a formation may increase production of selected formationfluids. For example, the amount and/or rate of heating may be controlledto produce formation fluids having an American Petroleum Institute(“API”) gravity greater than about 25. Heat and/or pressure may becontrolled to inhibit production of olefins in the produced fluids.

[0066] Controlling formation conditions to control the pressure ofhydrogen in the produced fluid may result in improved qualities of theproduced fluids. In some embodiments, it may be desirable to controlformation conditions so that the partial pressure of hydrogen in aproduced fluid is greater than about 0.5 bars absolute, as measured at aproduction well.

[0067] In one embodiment, a method of treating a relatively permeableformation in situ may include adding hydrogen to the selected sectionafter a temperature of the selected section is at least about 270° C.Other embodiments may include controlling a temperature of the formationby selectively adding hydrogen to the formation.

[0068] In certain embodiments, a relatively permeable formation may betreated in situ with a heat transfer fluid such as steam. In anembodiment, a method of formation may include injecting a heat transferfluid into a formation. Heat from the heat transfer fluid may transferto a selected section of the formation. The heat from the heat transferfluid may pyrolyze a substantial portion of the hydrocarbons within theselected section of the formation. The produced gas mixture may includehydrocarbons with an average API gravity greater than about 25°.

[0069] Furthermore, treating a relatively permeable formation with aheat transfer fluid may also mobilize hydrocarbons in the formation. Inan embodiment, a method of treating a formation may include injecting aheat transfer fluid into a formation, allowing the heat from the heattransfer fluid to transfer to a selected first section of the formation,and mobilizing and pyrolyzing at least some of the hydrocarbons withinthe selected first section of the formation. At least some of themobilized hydrocarbons may flow from the selected first section of theformation to a selected second section of the formation. The heat maypyrolyze at least some of the hydrocarbons within the selected secondsection of the formation. A gas mixture may be produced from theformation.

[0070] Another embodiment of treating a formation with a heat transferfluid may include a moving heat transfer fluid front. A method mayinclude injecting a heat transfer fluid into a formation and allowingthe heat transfer fluid to migrate through the formation. A size of aselected section may increase as a heat transfer fluid front migratesthrough an untreated portion of the formation. The selected section is aportion of the formation treated by the heat transfer fluid. Heat fromthe heat transfer fluid may transfer heat to the selected section. Theheat may pyrolyze at least some of the hydrocarbons within the selectedsection of the formation. The heat may also mobilize at least some ofthe hydrocarbons at the heat transfer fluid front. The mobilizedhydrocarbons may flow substantially parallel to the heat transfer fluidfront. The heat may pyrolyze at least a portion of the hydrocarbons inthe mobilized fluid and a gas mixture may be produced from theformation.

[0071] Simulations may be utilized to increase an understanding of insitu processes. Simulations may model heating of the formation from heatsources and the transfer of heat to a selected section of the formation.Simulations may require the input of model parameters, properties of theformation, operating conditions, process characteristics, and/or desiredparameters to determine operating conditions. Simulations may assessvarious aspects of an in situ process. For example, various aspects mayinclude, but not be limited to, deformation characteristics, heatingrates, temperatures within the formation, pressures, time to firstproduced fluids, and/or compositions of produced fluids.

[0072] Systems utilized in conducting simulations may include a centralprocessing unit (CPU), a data memory, and a system memory. The systemmemory and the data memory may be coupled to the CPU. Computer programsexecutable to implement simulations may be stored on the system memory.Carrier mediums may include program instructions that arecomputer-executable to simulate the in situ processes.

[0073] In one embodiment, a computer-implemented method and system oftreating a relatively permeable formation may include providing to acomputational system at least one set of operating conditions of an insitu system being used to apply heat to a formation. The in situ systemmay include at least one heat source. The method may further includeproviding to the computational system at least one desired parameter forthe in situ system. The computational system may be used to determine atleast one additional operating condition of the formation to achieve thedesired parameter.

[0074] In an embodiment, operating conditions may be determined bymeasuring at least one property of the formation. At least one measuredproperty may be input into a computer executable program. At least oneproperty of formation fluids selected to be produced from the formationmay also be input into the computer executable program. The program maybe operable to determine a set of operating conditions from at least theone or more measured properties. The program may also determine the setof operating conditions from at least one property of the selectedformation fluids. The determined set of operating conditions mayincrease production of selected formation fluids from the formation.

[0075] In some embodiments, a property of the formation and an operatingcondition used in the in situ process may be provided to a computersystem to model the in situ process to determine a processcharacteristic.

[0076] In an embodiment, a heat input rate for an in situ process fromtwo or more heat sources may be simulated on a computer system. Adesired parameter of the in situ process may be provided to thesimulation. The heat input rate from the heat sources may be controlledto achieve the desired parameter.

[0077] Alternatively, a heat input property may be provided to acomputer system to assess heat injection rate data using a simulation.In addition, a property of the formation may be provided to the computersystem. The property and the heat injection rate data may be utilized bya second simulation to determine a process characteristic for the insitu process as a function of time.

[0078] Values for the model parameters may be adjusted using processcharacteristics from a series of simulations. The model parameters maybe adjusted such that the simulated process characteristics correspondto process characteristics in situ. After the model parameters have beenmodified to correspond to the in situ process, a process characteristicor a set of process characteristics based on the modified modelparameters may be determined. In certain embodiments, multiplesimulations may be run such that the simulated process characteristicscorrespond to the process characteristics in situ.

[0079] In some embodiments, operating conditions may be supplied to asimulation to assess a process characteristic. Additionally, a desiredvalue of a process characteristic for the in situ process may beprovided to the simulation to assess an operating condition that yieldsthe desired value.

[0080] In certain embodiments, databases in memory on a computer may beused to store relationships between model parameters, properties of theformation, operating conditions, process characteristics, desiredparameters, etc. These databases may be accessed by the simulations toobtain inputs. For example, after desired values of processcharacteristics are provided to simulations, an operating condition maybe assessed to achieve the desired values using these databases.

[0081] In some embodiments, computer systems may utilize inputs in asimulation to assess information about the in situ process. In someembodiments, the assessed information may be used to operate the in situprocess. Alternatively, the assessed information and a desired parametermay be provided to a second simulation to obtain information. Thisobtained information may be used to operate the in situ process.

[0082] In an embodiment, a method of modeling may include simulating oneor more stages of the in situ process. Operating conditions from the oneor more stages may be provided to a simulation to assess a processcharacteristic of the one or more stages.

[0083] In an embodiment, operating conditions may be assessed bymeasuring at least one property of the formation. At least the measuredproperties may be input into a computer executable program. At least oneproperty of formation fluids selected to be produced from the formationmay also be input into the computer executable program. The program maybe operable to assess a set of operating conditions from at least theone or more measured properties. The program may also determine the setof operating conditions from at least one property of the selectedformation fluids. The assessed set of operating conditions may increaseproduction of selected formation fluids from the formation.

[0084] In one embodiment, a method for controlling an in situ system oftreating a relatively permeable formation may include monitoring atleast one acoustic event within the formation using at least oneacoustic detector placed within a wellbore in the formation. At leastone acoustic event may be recorded with an acoustic monitoring system.The method may also include analyzing the at least one acoustic event todetermine at least one property of the formation. The in situ system maybe controlled based on the analysis of the at least one acoustic event.

[0085] An embodiment of a method of determining a heating rate fortreating a relatively permeable formation in situ may include conductingan experiment at a relatively constant heating rate. The results of theexperiment may be used to determine a heating rate for treating theformation in situ. The determined heating rate may be used to determinea well spacing in the formation.

[0086] In an embodiment, a method of predicting characteristics of aformation fluid may include determining an isothermal heatingtemperature that corresponds to a selected heating rate for theformation. The determined isothermal temperature may be used in anexperiment to determine at least one product characteristic of theformation fluid produced from the formation for the selected heatingrate. Certain embodiments may include altering a composition offormation fluids produced from a relatively permeable formation byaltering a location of a production well with respect to a heater well.For example, a production well may be located with respect to a heaterwell such that a non-condensable gas fraction of produced hydrocarbonfluids may be larger than a condensable gas fraction of the producedhydrocarbon fluids.

[0087] Condensable hydrocarbons produced from the formation willtypically include paraffins, cycloalkanes, mono-aromatics, anddi-aromatics as major components. Such condensable hydrocarbons may alsoinclude other components such as tri-aromatics, etc.

[0088] In certain embodiments, a majority of the hydrocarbons inproduced fluid may have a carbon number of less than approximately 25.Alternatively, less than about 15 weight % of the hydrocarbons in thefluid may have a carbon number greater than approximately 25. In otherembodiments, fluid produced may have a weight ratio of hydrocarbonshaving carbon numbers from 2 through 4, to methane, of greater thanapproximately 1 (e.g., for heavy hydrocarbons). The non-condensablehydrocarbons may include, but are not limited to, hydrocarbons havingcarbon numbers less than 5.

[0089] In certain embodiments, the API gravity of the hydrocarbons inproduced fluid may be approximately 25 or above (e.g., 30, 40, 50,etc.). In certain embodiments, the hydrogen to carbon atomic ratio inproduced fluid may be at least approximately 1.7 (e.g., 1.8, 1.9, etc.).

[0090] Condensable hydrocarbons of a produced fluid may also includeolefins. For example, the olefin content of the condensable hydrocarbonsmay be from about 0.1 weight % to about 15 weight %. Alternatively, theolefin content of the condensable hydrocarbons may be from about 0.1weight % to about 2.5 weight % or, in some embodiments, less than about5 weight %.

[0091] Non-condensable hydrocarbons of a produced fluid may also includeolefins. For example, the olefin content of the non-condensablehydrocarbons may be gauged using the ethene/ethane molar ratio. Incertain embodiments, the ethene/ethane molar ratio may range from about0.001 to about 0.15.

[0092] Fluid produced from the formation may include aromatic compounds.For example, the condensable hydrocarbons may include an amount ofaromatic compounds greater than about 20 weight % or about 25 weight %of the condensable hydrocarbons. The condensable hydrocarbons may alsoinclude relatively low amounts of compounds with more than two rings inthem (e.g., tri-aromatics or above). For example, the condensablehydrocarbons may include less than about 1 weight %, 2 weight %, orabout 5 weight % of tri-aromatics or above in the condensablehydrocarbons.

[0093] In particular, in certain embodiments, asphaltenes (i.e., largemulti-ring aromatics that are substantially insoluble in hydrocarbons)make up less than about 0.1 weight % of the condensable hydrocarbons.For example, the condensable hydrocarbons may include an asphaltenecomponent of from about 0.0 weight % to about 0.1 weight % or, in someembodiments, less than about 0.3 weight %.

[0094] Condensable hydrocarbons of a produced fluid may also includerelatively large amounts of cycloalkanes. For example, the condensablehydrocarbons may include a cycloalkane component of up to 30 weight %(e.g., from about 5 weight % to about 30 weight %) of the condensablehydrocarbons.

[0095] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing nitrogen. Forexample, less than about 1 weight % (when calculated on an elementalbasis) of the condensable hydrocarbons is nitrogen (e.g., typically thenitrogen is in nitrogen containing compounds such as pyridines, amines,amides, etc.).

[0096] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing oxygen. Forexample, in certain embodiments (e.g., for heavy hydrocarbons), lessthan about 1 weight % (when calculated on an elemental basis) of thecondensable hydrocarbons is oxygen (e.g., typically the oxygen is inoxygen containing compounds such as phenols, substituted phenols,ketones, etc.). In some instances, certain compounds containing oxygen(e.g., phenols) may be valuable and, as such, may be economicallyseparated from the produced fluid.

[0097] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing sulfur. Forexample, less than about 1 weight % (when calculated on an elementalbasis) of the condensable hydrocarbons is sulfur (e.g., typically thesulfur is in sulfur containing compounds such as thiophenes, mercaptans,etc.).

[0098] Furthermore, the fluid produced from the formation may includeammonia (typically the ammonia condenses with the water, if any,produced from the formation). For example, the fluid produced from theformation may in certain embodiments include about 0.05 weight % or moreof ammonia. Certain formations may produce larger amounts of ammonia(e.g., up to about 10 weight % of the total fluid produced may beammonia).

[0099] Furthermore, a produced fluid from the formation may also includemolecular hydrogen (H₂), water, carbon dioxide, hydrogen sulfide, etc.For example, the fluid may include a H₂ content between about 10 volume% and about 80 volume % of the non-condensable hydrocarbons.

[0100] Certain embodiments may include heating to yield at least about15 weight % of a total organic carbon content of at least some of therelatively permeable formation into formation fluids.

[0101] In certain embodiments, heating of the selected section of theformation may be controlled to pyrolyze at least about 20 weight % (orin some embodiments about 25 weight %) of the hydrocarbons within theselected section of the formation.

[0102] Formation fluids produced from a section of the formation maycontain one or more components that may be separated from the formationfluids. In addition, conditions within the formation may be controlledto increase production of a desired component.

[0103] In certain embodiments, a method of converting pyrolysis fluidsinto olefins may include converting formation fluids into olefins. Anembodiment may include separating olefins from fluids produced from aformation.

[0104] An embodiment of a method of enhancing BTEX compounds (i.e.,benzene, toluene, ethylbenzene, and xylene compounds) produced in situin a relatively permeable formation may include controlling at least onecondition within a portion of the formation to enhance production ofBTEX compounds in formation fluid. In another embodiment, a method mayinclude separating at least a portion of the BTEX compounds from theformation fluid. In addition, the BTEX compounds may be separated fromthe formation fluids after the formation fluids are produced. In otherembodiments, at least a portion of the produced formation fluids may beconverted into BTEX compounds.

[0105] In one embodiment, a method of enhancing naphthalene productionfrom an in situ relatively permeable formation may include controllingat least one condition within at least a portion of the formation toenhance production of naphthalene in formation fluid. In anotherembodiment, naphthalene may be separated from produced formation fluids.

[0106] Certain embodiments of a method of enhancing anthraceneproduction from an in situ relatively permeable formation may includecontrolling at least one condition within at least a portion of theformation to enhance production of anthracene in formation fluid. In anembodiment, anthracene may be separated from produced formation fluids.

[0107] In one embodiment, a method of separating ammonia from fluidsproduced from an in situ relatively permeable formation may includeseparating at least a portion of the ammonia from the produced fluid.Furthermore, an embodiment of a method of generating ammonia from fluidsproduced from a formation may include hydrotreating at least a portionof the produced fluids to generate ammonia.

[0108] In an embodiment, a method of enhancing pyridines production froman in situ relatively permeable formation may include controlling atleast one condition within at least a portion of the formation toenhance production of pyridines in formation fluid. Additionally,pyridines may be separated from produced formation fluids.

[0109] In certain embodiments, a method of selecting a relativelypermeable formation to be treated in situ such that production ofpyridines is enhanced may include examining pyridines concentrations ina plurality of samples from relatively permeable formations. The methodmay further include selecting a formation for treatment at leastpartially based on the pyridines concentrations. Consequently, theproduction of pyridines to be produced from the formation may beenhanced.

[0110] In an embodiment, a method of enhancing pyrroles production froman in situ relatively permeable formation may include controlling atleast one condition within at least a portion of the formation toenhance production of pyrroles in formation fluid. In addition, pyrrolesmay be separated from produced formation fluids.

[0111] In certain embodiments, a relatively permeable formation to betreated in situ may be selected such that production of pyrroles isenhanced. The method may include examining pyrroles concentrations in aplurality of samples from relatively permeable formations. The formationmay be selected for treatment at least partially based on the pyrrolesconcentrations, thereby enhancing the production of pyrroles to beproduced from such formation.

[0112] In one embodiment, thiophenes production from an in siturelatively permeable formation may be enhanced by controlling at leastone condition within at least a portion of the formation to enhanceproduction of thiophenes in formation fluid. Additionally, thethiophenes may be separated from produced formation fluids.

[0113] An embodiment of a method of selecting a relatively permeableformation to be treated in situ such that production of thiophenes isenhanced may include examining thiophenes concentrations in a pluralityof samples from relatively permeable formations. The method may furtherinclude selecting a formation for treatment at least partially based onthe thiophenes concentrations, thereby enhancing the production ofthiophenes from such formations.

[0114] Certain embodiments may include providing a reducing agent to atleast a portion of the formation. A reducing agent provided to a portionof the formation during heating may increase production of selectedformation fluids. A reducing agent may include, but is not limited to,molecular hydrogen. For example, pyrolyzing at least some hydrocarbonsin a relatively permeable formation may include forming hydrocarbonfragments. Such hydrocarbon fragments may react with each other andother compounds present in the formation. Reaction of these hydrocarbonfragments may increase production of olefin and aromatic compounds fromthe formation. Therefore, a reducing agent provided to the formation mayreact with hydrocarbon fragments to form selected products and/orinhibit the production of non-selected products.

[0115] In an embodiment, a hydrogenation reaction between a reducingagent provided to a relatively permeable formation and at least some ofthe hydrocarbons within the formation may generate heat. The generatedheat may be allowed to transfer such that at least a portion of theformation may be heated. A reducing agent such as molecular hydrogen mayalso be autogenously generated within a portion of a relativelypermeable formation during an in situ conversion process forhydrocarbons. The autogenously generated molecular hydrogen mayhydrogenate formation fluids within the formation. Allowing formationwaters to contact hot carbon in the spent formation may generatemolecular hydrogen. Cracking an injected hydrocarbon fluid may alsogenerate molecular hydrogen.

[0116] Certain embodiments may also include providing a fluid producedin a first portion of a relatively permeable formation to a secondportion of the formation. A fluid produced in a first portion of arelatively permeable formation may be used to produce a reducingenvironment in a second portion of the formation. For example, molecularhydrogen generated in a first portion of a formation may be provided toa second portion of the formation. Alternatively, at least a portion offormation fluids produced from a first portion of the formation may beprovided to a second portion of the formation to provide a reducingenvironment within the second portion.

[0117] In an embodiment, a method for hydrotreating a compound in aheated formation in situ may include controlling the H₂ partial pressurein a selected section of the formation, such that sufficient H₂ may bepresent in the selected section of the formation for hydrotreating. Themethod may further include providing a compound for hydrotreating to atleast the selected section of the formation and producing a mixture fromthe formation that includes at least some of the hydrotreated compound.

[0118] In certain embodiments, a mass of at least a portion of theformation may be reduced due, for example, to the production offormation fluids from the formation. As such, a permeability andporosity of at least a portion of the formation may increase. Inaddition, removing water during the heating may also increase thepermeability and porosity of at least a portion of the formation.

[0119] In situ processes may be used to produce hydrocarbons, hydrogenand other formation fluids from a relatively permeable formation thatincludes heavy hydrocarbons (e.g., from tar sands). Heating may be usedto mobilize the heavy hydrocarbons within the formation and then topyrolyze heavy hydrocarbons within the formation to form pyrolyzationfluids. Formation fluids produced during pyrolyzation may be removedfrom the formation through production wells.

[0120] In certain embodiments, fluid (e.g., gas) may be provided to arelatively permeable formation. The gas may be used to pressurize theformation. Pressure in the formation may be selected to controlmobilization of fluid within the formation. For example, a higherpressure may increase the mobilization of fluid within the formationsuch that fluids may be produced at a higher rate.

[0121] In an embodiment, a portion of a relatively permeable formationmay be heated to reduce a viscosity of the heavy hydrocarbons within theformation. The reduced viscosity heavy hydrocarbons may be mobilized.The mobilized heavy hydrocarbons may flow to a selected pyrolyzationsection of the formation. A gas may be provided into the relativelypermeable formation to increase a flow of the mobilized heavyhydrocarbons into the selected pyrolyzation section. Such a gas may be,for example, carbon dioxide. The carbon dioxide may, in someembodiments, be stored in the formation after removal of the heavyhydrocarbons. A majority of the heavy hydrocarbons within the selectedpyrolyzation section may be pyrolyzed. Pyrolyzation of the mobilizedheavy hydrocarbons may upgrade the heavy hydrocarbons to a moredesirable product. The pyrolyzed heavy hydrocarbons may be removed fromthe formation through a production well. In some embodiments, themobilized heavy hydrocarbons may be removed from the formation through aproduction well without upgrading or pyrolyzing the heavy hydrocarbons.

[0122] Hydrocarbon fluids produced from the formation may vary dependingon conditions within the formation. For example, a heating rate of aselected pyrolyzation section may be controlled to increase theproduction of selected products. In addition, pressure within theformation may be controlled to vary the composition of the producedfluids.

[0123] An embodiment of a method for producing a selected productcomposition from a relatively permeable formation containing heavyhydrocarbons in situ may include providing heat from one or more heatsources to at least one portion of the formation and allowing the heatto transfer to a selected section of the formation. The method mayfurther include producing a product from one or more of the selectedsections and blending two or more of the products to produce a producthaving about the selected product composition.

[0124] In an embodiment, heat is provided from a first set of heatsources to a first section of a relatively permeable formation topyrolyze a portion of the hydrocarbons in the first section. Heat mayalso be provided from a second set of heat sources to a second sectionof the formation. The heat may reduce the viscosity of hydrocarbons inthe second section so that a portion of the hydrocarbons in the secondsection are able to move. A portion of the hydrocarbons from the secondsection may be induced to flow into the first section. A mixture ofhydrocarbons may be produced from the formation. The produced mixturemay include at least some pyrolyzed hydrocarbons.

[0125] In an embodiment, heat is provided from heat sources to a portionof a relatively permeable formation. The heat may transfer from the heatsources to a selected section of the formation to decrease a viscosityof hydrocarbons within the selected section. A gas may be provided tothe selected section of the formation. The gas may displace hydrocarbonsfrom the selected section towards a production well or production wells.A mixture of hydrocarbons may be produced from the selected sectionthrough the production well or production wells.

[0126] In some embodiments, energy supplied to a heat source or to asection of a heat source may be selectively limited to controltemperature and to inhibit coke formation at or near the heat source. Insome embodiments, a mixture of hydrocarbons may be produced throughportions of a heat source that are operated to inhibit coke formation.

[0127] In certain embodiments, a quality of a produced mixture may becontrolled by varying a location for producing the mixture. The locationof production may be varied by varying the depth in the formation fromwhich fluid is produced relative an overburden or underburden. Thelocation of production may also be varied by varying which productionwells are used to produce fluid. In some embodiments, the productionwells used to remove fluid may be chosen based on a distance of theproduction wells from activated heat sources.

[0128] In an embodiment, a blending agent may be produced from aselected section of a formation. A portion of the blending agent may bemixed with heavy hydrocarbons to produce a mixture having a selectedcharacteristic (e.g., density, viscosity, and/or stability). In certainembodiments, the heavy hydrocarbons may be produced from another sectionof the formation used to produce the blending agent. In someembodiments, the heavy hydrocarbons may be produced from anotherformation.

[0129] In some embodiments, heat may be provided to a selected sectionof a relatively permeable formation to pyrolyze some hydrocarbons in alower portion of the formation. A mixture of hydrocarbons may beproduced from an upper portion of the formation. The mixture ofhydrocarbons may include at least some pyrolyzed hydrocarbons from thelower portion of the formation.

[0130] In certain embodiments, a production rate of fluid from theformation may be controlled to adjust an average time that hydrocarbonsare in, or flowing into, a pyrolysis zone or exposed to pyrolysistemperatures. Controlling the production rate may allow for productionof a large quantity of hydrocarbons of a desired quality from theformation.

[0131] A heated formation may also be used to produce synthesis gas.Synthesis gas may be produced from the formation prior to or subsequentto producing a formation fluid from the formation. For example,synthesis gas generation may be commenced before and/or after formationfluid production decreases to an uneconomical level. Heat provided topyrolyze hydrocarbons within the formation may also be used to generatesynthesis gas. For example, if a portion of the formation is at atemperature from approximately 270° C. to approximately 375° C. (or 400°C. in some embodiments) after pyrolyzation, then less additional heat isgenerally required to heat such portion to a temperature sufficient tosupport synthesis gas generation.

[0132] In certain embodiments, synthesis gas is produced afterproduction of pyrolysis fluids. For example, after pyrolysis of aportion of a formation, synthesis gas may be produced from carbon and/orhydrocarbons remaining within the formation. Pyrolysis of the portionmay produce a relatively high, substantially uniform permeabilitythroughout the portion. Such a relatively high, substantially uniformpermeability may allow generation of synthesis gas from a significantportion of the formation at relatively low pressures. The portion mayalso have a large surface area and/or surface area/volume. The largesurface area may allow synthesis gas producing reactions to besubstantially at equilibrium conditions during synthesis gas generation.The relatively high, substantially uniform permeability may result in arelatively high recovery efficiency of synthesis gas, as compared tosynthesis gas generation in a relatively permeable formation that hasnot been so treated.

[0133] Pyrolysis of at least some hydrocarbons may in some embodimentsconvert about 15 weight % or more of the carbon initially available.Synthesis gas generation may convert approximately up to an additional80 weight % or more of carbon initially available within the portion. Insitu production of synthesis gas from a relatively permeable formationmay allow conversion of larger amounts of carbon initially availablewithin the portion. The amount of conversion achieved may, in someembodiments, be limited by subsidence concerns.

[0134] Certain embodiments may include providing heat from one or moreheat sources to heat the formation to a temperature sufficient to allowsynthesis gas generation (e.g., in a range of approximately 400° C. toapproximately 1200° C. or higher). At a lower end of the temperaturerange, generated synthesis gas may have a high hydrogen (H₂) to carbonmonoxide (CO) ratio. At an upper end of the temperature range, generatedsynthesis gas may include mostly H₂ and CO in lower ratios (e.g.,approximately a 1:1 ratio).

[0135] Heat sources for synthesis gas production may include any of theheat sources as described in any of the embodiments set forth herein.Alternatively, heating may include transferring heat from a heattransfer fluid (e.g., steam or combustion products from a burner)flowing within a plurality of wellbores within the formation.

[0136] A synthesis gas generating fluid (e.g., liquid water, steam,carbon dioxide, air, oxygen, hydrocarbons, and mixtures thereof) may beprovided to the formation. For example, the synthesis gas generatingfluid mixture may include steam and oxygen. In an embodiment, asynthesis gas generating fluid may include aqueous fluid produced bypyrolysis of at least some hydrocarbons within one or more otherportions of the formation. Providing the synthesis gas generating fluidmay alternatively include raising a water table of the formation toallow water to flow into it. Synthesis gas generating fluid may also beprovided through at least one injection wellbore. The synthesis gasgenerating fluid will generally react with carbon in the formation toform H₂, water, methane, CO₂, and/or CO. A portion of the carbon dioxidemay react with carbon in the formation to generate carbon monoxide.Hydrocarbons such as ethane may be added to a synthesis gas generatingfluid. When introduced into the formation, the hydrocarbons may crack toform hydrogen and/or methane. The presence of methane in producedsynthesis gas may increase the heating value of the produced synthesisgas.

[0137] Synthesis gas generation is, in some embodiments, an endothermicprocess. Additional heat may be added to the formation during synthesisgas generation to maintain a high temperature within the formation. Theheat may be added from heater wells and/or from oxidizing carbon and/orhydrocarbons within the formation.

[0138] In an embodiment, an oxidant may be added to a synthesis gasgenerating fluid. The oxidant may include, but is not limited to, air,oxygen enriched air, oxygen, hydrogen peroxide, other oxidizing fluids,or combinations thereof. The oxidant may react with carbon within theformation to exothermically generate heat. Reaction of an oxidant withcarbon in the formation may result in production of CO₂ and/or CO.Introduction of an oxidant to react with carbon in the formation mayeconomically allow raising the formation temperature high enough toresult in generation of significant quantities of H₂ and CO fromhydrocarbons within the formation. Synthesis gas generation may be via abatch process or a continuous process.

[0139] Synthesis gas may be produced from the formation through one ormore producer wells that include one or more heat sources. Such heatsources may operate to promote production of the synthesis gas with adesired composition.

[0140] Certain embodiments may include monitoring a composition of theproduced synthesis gas and then controlling heating and/or controllinginput of the synthesis gas generating fluid to maintain the compositionof the produced synthesis gas within a desired range. For example, insome embodiments (e.g., such as when the synthesis gas will be used as afeedstock for a Fischer-Tropsch process), a desired composition of theproduced synthesis gas may have a ratio of hydrogen to carbon monoxideof about 1.8:1 to 2.2:1 (e.g., about 2:1 or about 2.1:1). In someembodiments (such as when the synthesis gas will be used as a feedstockto make methanol), such ratio may be about 3:1 (e.g., about 2.8:1 to3.2:1).

[0141] Certain embodiments may include blending a first synthesis gaswith a second synthesis gas to produce synthesis gas of a desiredcomposition. The first and the second synthesis gases may be producedfrom different portions of the formation.

[0142] Synthesis gases may be converted to heavier condensablehydrocarbons. For example, a Fischer-Tropsch hydrocarbon synthesisprocess may convert synthesis gas to branched and unbranched paraffins.Paraffins produced from the Fischer-Tropsch process may be used toproduce other products such as diesel, jet fuel, and naphtha products.The produced synthesis gas may also be used in a catalytic methanationprocess to produce methane. Alternatively, the produced synthesis gasmay be used for production of methanol, gasoline and diesel fuel,ammonia, and middle distillates. Produced synthesis gas may be used toheat the formation as a combustion fuel. Hydrogen in produced synthesisgas may be used to upgrade oil.

[0143] Synthesis gas may also be used for other purposes. Synthesis gasmay be combusted as fuel. Synthesis gas may also be used forsynthesizing a wide range of organic and/or inorganic compounds, such ashydrocarbons and ammonia. Synthesis gas may be used to generateelectricity by combusting it as a fuel, by reducing the pressure of thesynthesis gas in turbines, and/or using the temperature of the synthesisgas to make steam (and then run turbines). Synthesis gas may also beused in an energy generation unit such as a molten carbonate fuel cell,a solid oxide fuel cell, or other type of fuel cell.

[0144] Certain embodiments may include separating a fuel cell feedstream from fluids produced from pyrolysis of at least some of thehydrocarbons within a formation. The fuel cell feed stream may includeH₂, hydrocarbons, and/or carbon monoxide. In addition, certainembodiments may include directing the fuel cell feed stream to a fuelcell to produce electricity. The electricity generated from thesynthesis gas or the pyrolyzation fluids in the fuel cell may powerelectric heaters, which may heat at least a portion of the formation.Certain embodiments may include separating carbon dioxide from a fluidexiting the fuel cell. Carbon dioxide produced from a fuel cell or aformation may be used for a variety of purposes.

[0145] In certain embodiments, synthesis gas produced from a heatedformation may be transferred to an additional area of the formation andstored within the additional area of the formation for a length of time.The conditions of the additional area of the formation may inhibitreaction of the synthesis gas. The synthesis gas may be produced fromthe additional area of the formation at a later time.

[0146] In some embodiments, treating a formation may include injectingfluids into the formation. The method may include providing heat to theformation, allowing the heat to transfer to a selected section of theformation, injecting a fluid into the selected section, and producinganother fluid from the formation. Additional heat may be provided to atleast a portion of the formation, and the additional heat may be allowedto transfer from at least the portion to the selected section of theformation. At least some hydrocarbons may be pyrolyzed within theselected section and a mixture may be produced from the formation.Another embodiment may include leaving a section of the formationproximate the selected section substantially unleached. The unleachedsection may inhibit the flow of water into the selected section.

[0147] In an embodiment, heat may be provided to the formation. The heatmay be allowed to transfer to a selected section of the formation suchthat dissociation of carbonate minerals is inhibited. At least somehydrocarbons may be pyrolyzed within the selected section and a mixtureproduced from the formation. The method may further include reducing atemperature of the selected section and injecting a fluid into theselected section. Another fluid may be produced from the formation.Alternatively, subsequent to providing heat and allowing heat totransfer, a method may include injecting a fluid into the selectedsection and producing another fluid from the formation. Similarly, amethod may include injecting a fluid into the selected section andpyrolyzing at least some hydrocarbons within the selected section of theformation after providing heat and allowing heat to transfer to theselected section.

[0148] In an embodiment that includes injecting fluids, a method oftreating a formation may include providing heat from one or more heatsources and allowing the heat to transfer to a selected section of theformation such that a temperature of the selected section is less thanabout a temperature at which nahcolite dissociates. A fluid may beinjected into the selected section and another fluid may be producedfrom the formation. The method may further include providing additionalheat to the formation, allowing the additional heat to transfer to theselected section of the formation, and pyrolyzing at least somehydrocarbons within the selected section. A mixture may then be producedfrom the formation.

[0149] Certain embodiments that include injecting fluids may alsoinclude controlling the heating of the formation. A method may includeproviding heat to the formation, controlling the heat such that aselected section is at a first temperature, injecting a fluid into theselected section, and producing another fluid from the formation. Themethod may further include controlling the heat such that the selectedsection is at a second temperature that is greater than the firsttemperature. Heat may be allowed to transfer from the selected section,and at least some hydrocarbons may be pyrolyzed within the selectedsection of the formation. A mixture may be produced from the formation.

[0150] A further embodiment that includes injecting fluids may includeproviding heat to a formation, allowing the heat to transfer to aselected section of the formation, injecting a first fluid into theselected section, and producing a second fluid from the formation. Themethod may further include providing additional heat, allowing theadditional heat to transfer to the selected section of the formation,pyrolyzing at least some hydrocarbons within the selected section of theformation, and producing a mixture from the formation. In addition, atemperature of the selected section may be reduced and a third fluid maybe injected into the selected section. A fourth fluid may be producedfrom the formation.

[0151] In some embodiments, migration of fluids into and/or out of atreatment area may be inhibited. Inhibition of migration of fluids mayoccur before, during, and/or after an in situ treatment process. Forexample, migration of fluids may be inhibited while heat is providedfrom one or more heat sources to at least a portion of the treatmentarea. The heat may be allowed to transfer to at least a portion of thetreatment area. Fluids may be produced from the treatment area.

[0152] Barriers may be used to inhibit migration of fluids into and/orout of a treatment area in a formation. Barriers may include, but arenot limited to naturally occurring portions (e.g., overburden and/orunderburden), frozen barrier zones, low temperature barrier zones, groutwalls, sulfur wells, dewatering wells, and/or injection wells. Barriersmay define the treatment area. Alternatively, barriers may be providedto a portion of the treatment area.

[0153] In an embodiment, a method of treating a relatively permeableformation in situ may include providing a refrigerant to a plurality ofbarrier wells to form a low temperature barrier zone. The method mayfurther include establishing a low temperature barrier zone. In someembodiments, the temperature within the low temperature barrier zone maybe lowered to inhibit the flow of water into or out of at least aportion of a treatment area in the formation.

[0154] Certain embodiments of treating a relatively permeable formationin situ may include providing a refrigerant to a plurality of barrierwells to form a frozen barrier zone. The frozen barrier zone may inhibitmigration of fluids into and/or out of the treatment area. In certainembodiments, a portion of the treatment area is below a water table ofthe formation.

[0155] In addition, the method may include controlling pressure tomaintain a fluid pressure within the treatment area above a hydrostaticpressure of the formation and producing a mixture of fluids from theformation.

[0156] Barriers may be provided to a portion of the formation prior to,during, and after providing heat from one or more heat sources to thetreatment area. For example, a barrier-may be provided to a portion ofthe formation that has previously undergone a conversion process.

[0157] Fluid may be introduced to a portion of the formation that haspreviously undergone an in situ conversion process. The fluid may beproduced from the formation in a mixture, which may contain additionalfluids present in the formation. In some embodiments, the producedmixture may be provided to an energy producing unit.

[0158] In some embodiments, one or more conditions in a selected sectionmay be controlled during an in situ conversion process to inhibitformation of carbon dioxide. Conditions may be controlled to producefluids having a carbon dioxide emission level that is less than aselected carbon dioxide level. For example, heat provided to theformation may be controlled to inhibit generation of carbon dioxide,while increasing production of molecular hydrogen.

[0159] In a similar manner, a method for producing methane from arelatively permeable formation in situ while minimizing production ofCO₂ may include controlling the heat from the one or more heat sourcesto enhance production of methane in the produced mixture and generatingheat via at least one or more of the heat sources in a manner thatminimizes CO₂ production. The methane may further include controlling atemperature proximate the production wellbore at or above adecomposition temperature of ethane.

[0160] In certain embodiments, a method for producing products from aheated formation may include controlling a condition within a selectedsection of the formation to produce a mixture having a carbon dioxideemission level below a selected baseline carbon dioxide emission level.In some embodiments, the mixture may be blended with a fluid to generatea product having a carbon dioxide emission level below the baseline.

[0161] In an embodiment, a method for producing methane from a heatedformation in situ may include providing heat from one or more heatsources to at least one portion of the formation and allowing the heatto transfer to a selected section of the formation. The method mayfurther include providing hydrocarbon compounds to at least the selectedsection of the formation and producing a mixture including methane fromthe hydrocarbons in the formation.

[0162] One embodiment of a method for producing hydrocarbons in a heatedformation may include forming a temperature gradient in at least aportion of a selected section of the heated formation and providing ahydrocarbon mixture to at least the selected section of the formation. Amixture may then be produced from a production well.

[0163] In certain embodiments, a method for upgrading hydrocarbons in aheated formation may include providing hydrocarbons to a selectedsection of the heated formation and allowing the hydrocarbons to crackin the heated formation. The cracked hydrocarbons may be a higher gradethan the provided hydrocarbons. The upgraded hydrocarbons may beproduced from the formation.

[0164] Cooling a portion of the formation after an in situ conversionprocess may provide certain benefits, such as increasing the strength ofthe rock in the formation (thereby mitigating subsidence), increasingabsorptive capacity of the formation, etc.

[0165] In an embodiment, a portion of a formation that has beenpyrolyzed and/or subjected to synthesis gas generation may be allowed tocool or may be cooled to form a cooled, spent portion within theformation. For example, a heated portion of a formation may be allowedto cool by transference of heat to an adjacent portion of the formation.The transference of heat may occur naturally or may be forced by theintroduction of heat transfer fluids through the heated portion and intoa cooler portion of the formation.

[0166] In alternate embodiments, recovering thermal energy from a posttreatment relatively permeable formation may include injecting a heatrecovery fluid into a portion of the formation. Heat from the formationmay transfer to the heat recovery fluid. The heat recovery fluid may beproduced from the formation. For example, introducing water to a portionof the formation may cool the portion. Water introduced into the portionmay be removed from the formation as steam. The removed steam or hotwater may be injected into a hot portion of the formation to createsynthesis gas

[0167] In an embodiment, hydrocarbons may be recovered from a posttreatment relatively permeable formation by injecting a heat recoveryfluid into a portion of the formation. Heat may vaporize at least someof the heat recovery fluid and at least some hydrocarbons in theformation. A portion of the vaporized recovery fluid and the vaporizedhydrocarbons may be produced from the formation.

[0168] In certain embodiments, fluids in the formation may be removedfrom a post treatment hydrocarbon formation by injecting a heat recoveryfluid into a portion of the formation. Heat may transfer to the heatrecovery fluid and a portion of the fluid may be produced from theformation. The heat recovery fluid produced from the formation mayinclude at least some of the fluids in the formation.

[0169] In one embodiment, a method of recovering excess heat from aheated formation may include providing a product stream to the heatedformation, such that heat transfers from the heated formation to theproduct stream. The method may further include producing the productstream from the heated formation and directing the product stream to aprocessing unit. The heat of the product stream may then be transferredto the processing unit. In an alternate method for recovering excessheat from a heated formation the heated product stream may be directedto another formation, such that heat transfers from the product streamto the other formation.

[0170] In one embodiment, a method of utilizing heat of a heatedformation may include placing a conduit in the formation, such thatconduit input may be located separately from conduit output. The conduitmay be heated by the heated formation to produce a region of reaction inat least a portion of the conduit. The method may further includedirecting a material through the conduit to the region of reaction. Thematerial may undergo change in the region of reaction. A product may beproduced from the conduit.

[0171] An embodiment of a method of utilizing heat of a heated formationmay include providing heat from one or more heat sources to at least oneportion of the formation and allowing the heat to transfer to a regionof reaction in the formation. Material may be directed to the region ofreaction and allowed to react in the region of reaction. A mixture maythen be produced from the formation.

[0172] In an embodiment, a portion of a relatively permeable formationmay be used to store and/or sequester materials (e.g., formation fluids,carbon dioxide). The conditions within the portion of the formation mayinhibit reactions of the materials. Materials may be may be stored inthe portion for a length of time. In addition, materials may be producedfrom the portion at a later time. Materials stored within the portionmay have been previously produced from the portion of the formation,and/or another portion of the formation.

[0173] After an in situ conversion process has been completed in aportion of the formation, fluid may be sequestered within the formation.In some embodiments, to store a significant amount of fluid within theformation, a temperature of the formation will often need to be lessthan about 100° C. Water may be introduced into at least a portion ofthe formation to generate steam and reduce a temperature of theformation. The steam may be removed from the formation. The steam may beutilized for various purposes, including, but not limited to, heatinganother portion of the formation, generating synthesis gas in anadjacent portion of the formation, generating electricity, and/or as asteam flood in a oil reservoir. After the formation has cooled, fluid(e.g., carbon dioxide) may be pressurized and sequestered in theformation. Sequestering fluid within the formation may result in asignificant reduction or elimination of fluid that is released to theenvironment due to operation of the in situ conversion process.

[0174] In alternate embodiments, carbon dioxide may be injected underpressure into the portion of the formation. The injected carbon dioxidemay adsorb onto hydrocarbons in the formation and/or reside in voidspaces such as pores in the formation. The carbon dioxide may begenerated during pyrolysis, synthesis gas generation, and/or extractionof useful energy. In some embodiments, carbon dioxide may be stored inrelatively deep relatively permeable formations and used to desorbmethane.

[0175] In one embodiment, a method for sequestering carbon dioxide in aheated formation may include precipitating carbonate compounds fromcarbon dioxide provided to a portion of the formation. In someembodiments, the portion may have previously undergone an in situconversion process. Carbon dioxide and a fluid may be provided to theportion of the formation. The fluid may combine with carbon dioxide inthe portion to precipitate carbonate compounds.

[0176] In an alternate embodiment, methane may be recovered from arelatively permeable formations by providing heat to the formation. Theheat may desorb a substantial portion of the methane within the selectedsection of the formation. At least a portion of the methane may beproduced from the formation.

[0177] In an embodiment, a method for purifying water in a spentformation may include providing water to the formation and filtering theprovided water in the formation. The filtered water may then be producedfrom the formation.

[0178] In an embodiment, treating a relatively permeable formation insitu may include injecting a recovery fluid into the formation. Heat maybe provided from one or more heat sources to the formation. The heat maytransfer from one or more of the heat sources to a selected section ofthe formation and vaporize a substantial portion of recovery fluid in atleast a portion of the selected section. The heat from the heat sourcesand the vaporized recovery fluid may pyrolyze at least some hydrocarbonswithin the selected section. A gas mixture may be produced from theformation. The produced gas mixture may include hydrocarbons with anaverage API gravity greater than about 25°.

[0179] In certain embodiments, a method of shutting-in an in situtreatment process in a relatively permeable formation may includeterminating heating from one or more heat sources providing heat to aportion of the formation. A pressure may be monitored and controlled inat least a portion of the formation. The pressure may be maintainedapproximately below a fracturing or breakthrough pressure of theformation.

[0180] One embodiment of a method of shutting-in an in situ treatmentprocess in a relatively permeable formation may include terminatingheating from one or more heat sources providing heat to a portion of theformation. Hydrocarbon vapor may be produced from the formation. Atleast a portion of the produced hydrocarbon vapor may be injected into aportion of a storage formation. The hydrocarbon vapor may be injectedinto a relatively high temperature formation. A substantial portion ofinjected hydrocarbons may be converted to coke and H₂ in the relativelyhigh temperature formation. Alternatively, the hydrocarbon vapor may bestored in a depleted formation.

BRIEF DESCRIPTION OF THE DRAWINGS

[0181] Further advantages of the present invention may become apparentto those skilled in the art with the benefit of the following detaileddescription of the preferred embodiments and upon reference to theaccompanying drawings in which:

[0182]FIG. 1 depicts an illustration of stages of heating a relativelypermeable formation.

[0183]FIG. 2 depicts an embodiment of a heat source pattern.

[0184]FIG. 3 depicts an embodiment of a heater well.

[0185]FIG. 4 depicts an embodiment of heater well.

[0186]FIG. 5 depicts an embodiment of heater well.

[0187]FIG. 6 illustrates a schematic view of multiple heaters branchedfrom a single well in a relatively permeable formation.

[0188]FIG. 7 illustrates a schematic of an elevated view of multipleheaters branched from a single well in a relatively permeable formation.

[0189]FIG. 8 depicts an embodiment of heater wells located in arelatively permeable formation.

[0190]FIG. 9 depicts an embodiment of a pattern of heater wells in arelatively permeable formation.

[0191]FIG. 10 depicts a schematic representation of an embodiment of amagnetostatic drilling operation.

[0192]FIG. 11 depicts a schematic of a portion of a magnetic string.

[0193]FIG. 12 depicts an embodiment of a heated portion of a relativelypermeable formation.

[0194]FIG. 13 depicts an embodiment of superposition of heat in arelatively permeable formation.

[0195]FIG. 14 illustrates an embodiment of a production well placed in aformation.

[0196]FIG. 15 depicts an embodiment of a pattern of heat sources andproduction wells in a relatively permeable formation.

[0197]FIG. 16 depicts an embodiment of a pattern of heat sources and aproduction well in a relatively permeable formation.

[0198]FIG. 17 illustrates a computational system.

[0199]FIG. 18 depicts a block diagram of a computational system.

[0200]FIG. 19 illustrates a flow chart of an embodiment of acomputer-implemented method for treating a formation based on acharacteristic of the formation.

[0201]FIG. 20 illustrates a schematic of an embodiment used to controlan in situ conversion process in a formation.

[0202]FIG. 21 illustrates a flowchart of an embodiment of a method formodeling an in situ process for treating a relatively permeableformation using a computer system.

[0203]FIG. 22 illustrates a plot of a porosity-permeabilityrelationship.

[0204]FIG. 23 illustrates a method for simulating heat transfer in aformation.

[0205]FIG. 24 illustrates a model for simulating a heat transfer rate ina formation.

[0206]FIG. 25 illustrates a flowchart of an embodiment of a method forusing a computer system to model an in situ conversion process.

[0207]FIG. 26 illustrates a flow chart of an embodiment of a method forcalibrating model parameters to match laboratory or field data for an insitu process.

[0208]FIG. 27 illustrates a flowchart of an embodiment of a method forcalibrating model parameters.

[0209]FIG. 28 illustrates a flow chart of an embodiment of a method forcalibrating model parameters for a second simulation method using asimulation method.

[0210]FIG. 29 illustrates a flow chart of an embodiment of a method fordesign and/or control of an in situ process.

[0211]FIG. 30 depicts a method of modeling one or more stages of atreatment process.

[0212]FIG. 31 illustrates a flow chart of an embodiment of method fordesigning and controlling an in situ process with a simulation method ona computer system.

[0213]FIG. 32 illustrates a model of a formation that may be used insimulations of deformation characteristics according to one embodiment.

[0214]FIG. 33 illustrates a schematic of a strip development accordingto one embodiment.

[0215]FIG. 34 depicts a schematic illustration of a treated portion thatmay be modeled with a simulation.

[0216]FIG. 35 depicts a horizontal cross section of a model of aformation for use by a simulation method according to one embodiment.

[0217]FIG. 36 illustrates a flow chart of an embodiment of a method formodeling deformation due to in situ treatment of a relatively permeableformation.

[0218]FIG. 37 illustrates a flow chart of an embodiment of a method forusing a computer system to design and control an in situ conversionprocess.

[0219]FIG. 38 illustrates a flow chart of an embodiment of a method fordetermining operating conditions to obtain desired deformationcharacteristics.

[0220]FIG. 39 illustrates the influence of operating pressure onsubsidence in a cylindrical model of a formation from a finite elementsimulation.

[0221]FIG. 40 illustrates influence of an untreated portion between twotreated portions.

[0222]FIG. 41 illustrates influence of an untreated portion between twotreated portions.

[0223]FIG. 42 illustrates a method for controlling an in situ processusing a computer system.

[0224]FIG. 43 illustrates a schematic of an embodiment for controllingan in situ process in a formation using a computer simulation method.

[0225]FIG. 44 illustrates several ways that information may betransmitted from an in situ process to a remote computer system.

[0226]FIG. 45 illustrates a schematic of an embodiment for controllingan in situ process in a formation using information.

[0227]FIG. 46 illustrates a schematic of an embodiment for controllingan in situ process in a formation using a simulation method and acomputer system.

[0228]FIG. 47 illustrates a flow chart of an embodiment of acomputer-implemented method for determining a selected overburdenthickness.

[0229]FIG. 48 illustrates a schematic diagram of a plan view of a zonebeing treated using an in situ conversion process.

[0230]FIG. 49 illustrates a schematic diagram of a cross-sectionalrepresentation of a zone being treated using an in situ conversionprocess.

[0231]FIG. 50 illustrates a flow chart of an embodiment of a method usedto monitor treatment of a formation.

[0232]FIG. 51 depicts an embodiment of a natural distributed combustorheat source.

[0233]FIG. 52 depicts an embodiment of a natural distributed combustorsystem for heating a formation.

[0234]FIG. 53 illustrates a cross-sectional representation of anembodiment of a natural distributed combustor having a second conduit.

[0235]FIG. 54 depicts a schematic representation of an embodiment of aheater well positioned within a relatively permeable formation.

[0236]FIG. 55 depicts a portion of an overburden of a formation with anatural distributed combustor heat source.

[0237]FIG. 56 depicts an embodiment of a natural distributed combustorheat source.

[0238]FIG. 57 depicts an embodiment of a natural distributed combustorheat source.

[0239]FIG. 58 depicts an embodiment of a natural distributed combustorsystem for heating a formation.

[0240]FIG. 59 depicts an embodiment of an insulated conductor heatsource.

[0241]FIG. 60 depicts an embodiment of a transition section of aninsulated conductor assembly.

[0242]FIG. 61 depicts an embodiment of an insulated conductor heatsource.

[0243]FIG. 62 depicts an embodiment of a wellhead of an insulatedconductor heat source.

[0244]FIG. 63 depicts an embodiment of a conductor-in-conduit heatsource in a formation.

[0245]FIG. 64 depicts an embodiment of three insulated conductor heatersplaced within a conduit.

[0246]FIG. 65 depicts an embodiment of a centralizer.

[0247]FIG. 66 depicts an embodiment of a centralizer.

[0248]FIG. 67 depicts an embodiment of a centralizer.

[0249]FIG. 68 depicts a cross-sectional representation of an embodimentof a removable conductor-in-conduit heat source.

[0250]FIG. 69 depicts an embodiment of a sliding connector.

[0251]FIG. 70 depicts an embodiment of a wellhead with aconductor-in-conduit heat source.

[0252]FIG. 71 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0253]FIG. 72 illustrates an enlarged view of an embodiment of ajunction of a conductor-in-conduit heater.

[0254]FIG. 73 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0255]FIG. 74 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0256]FIG. 75 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0257]FIG. 76 depicts a cross-sectional view of a portion of anembodiment of a cladding section coupled to a heater support and aconduit.

[0258]FIG. 77 illustrates a cross-sectional representation of anembodiment of a centralizer placed on a conductor.

[0259]FIG. 78 depicts a portion of an embodiment of aconductor-in-conduit heat source with a cutout view showing acentralizer on the conductor.

[0260]FIG. 79 depicts a cross-sectional representation of an embodimentof a centralizer.

[0261]FIG. 80 depicts a cross-sectional representation of an embodimentof a centralizer.

[0262]FIG. 81 depicts a top view of an embodiment of a centralizer.

[0263]FIG. 82 depicts a top view of an embodiment of a centralizer.

[0264]FIG. 83 depicts a cross-sectional representation of a portion ofan embodiment of a section of a conduit of a conduit-in-conductor heatsource with an insulation layer wrapped around the conductor.

[0265]FIG. 84 depicts a cross-sectional representation of an embodimentof a cladding section coupled to a low resistance conductor.

[0266]FIG. 85 depicts an embodiment of a conductor-in-conduit heatsource in a formation.

[0267]FIG. 86 depicts an embodiment for assembling aconductor-in-conduit heat source and installing the heat source in aformation.

[0268]FIG. 87 depicts an embodiment of a conductor-in-conduit heatsource to be installed in a formation.

[0269]FIG. 88 shows a cross-sectional representation of an end of atubular around which two pairs of diametrically opposite electrodes arearranged.

[0270]FIG. 89 depicts an embodiment of ends of two adjacent tubularsbefore forge welding.

[0271]FIG. 90 illustrates an end view of an embodiment of aconductor-in-conduit heat source heated by diametrically oppositeelectrodes.

[0272]FIG. 91 illustrates a cross-sectional representation of anembodiment of two conductor-in-conduit heat source sections before forgewelding.

[0273]FIG. 92 depicts an embodiment of heat sources installed in aformation.

[0274]FIG. 93 depicts an embodiment of a heat source in a formation.

[0275]FIG. 94 illustrates a cross-sectional representation of anembodiment of a heater with two oxidizers.

[0276]FIG. 95 illustrates a cross-sectional representation of anembodiment of a heater with an oxidizer and an electric heater.

[0277]FIG. 96 depicts a cross-sectional representation of an embodimentof a heater with an oxidizer and a flameless distributed combustorheater.

[0278]FIG. 97 illustrates a cross-sectional representation of anembodiment of a multilateral downhole combustor heater.

[0279]FIG. 98 illustrates a cross-sectional representation of anembodiment of a downhole combustor heater with two conduits.

[0280]FIG. 99 illustrates a cross-sectional representation of anembodiment of a downhole combustor.

[0281]FIG. 100 depicts an embodiment of a heat source for a relativelypermeable formation.

[0282]FIG. 101 depicts a representation of a portion of a piping layoutfor heating a formation using downhole combustors.

[0283]FIG. 102 depicts a schematic representation of an embodiment of aheater well positioned within a relatively permeable formation.

[0284]FIG. 103 depicts an embodiment of a heat source positioned in arelatively permeable formation.

[0285]FIG. 104 depicts a schematic representation of an embodiment of aheat source positioned in a relatively permeable formation.

[0286]FIG. 105 depicts an embodiment of a surface combustor heat source.

[0287]FIG. 106 depicts an embodiment of a conduit for a heat source witha portion of an inner conduit shown cut away to show a center tube.

[0288]FIG. 107 depicts an embodiment of a flameless combustor heatsource.

[0289]FIG. 108 illustrates a representation of an embodiment of anexpansion mechanism coupled to a heat source in an opening in aformation.

[0290]FIG. 109 illustrates a schematic of a thermocouple placed in awellbore.

[0291]FIG. 110 depicts a schematic of a well embodiment for usingpressure waves to measure temperature within a wellbore.

[0292]FIG. 111 illustrates a schematic of an embodiment that uses windto generate electricity to heat a formation.

[0293]FIG. 112 depicts an embodiment of a windmill for generatingelectricity.

[0294]FIG. 113 illustrates a schematic of an embodiment for using solarpower to heat a formation.

[0295]FIG. 114 depicts an embodiment of using pyrolysis water togenerate synthesis gas in a formation.

[0296]FIG. 115 depicts an embodiment of synthesis gas production in aformation.

[0297]FIG. 116 depicts an embodiment of continuous synthesis gasproduction in a formation.

[0298]FIG. 117 depicts an embodiment of batch synthesis gas productionin a formation.

[0299]FIG. 118 depicts an embodiment of producing energy with synthesisgas produced from a relatively permeable formation.

[0300]FIG. 119 depicts an embodiment of producing energy withpyrolyzation fluid produced from a relatively permeable formation.

[0301]FIG. 120 depicts an embodiment of synthesis gas production from aformation.

[0302]FIG. 121 depicts an embodiment of sequestration of carbon dioxideproduced during pyrolysis in a relatively permeable formation.

[0303]FIG. 122 depicts an embodiment of producing energy with synthesisgas produced from a relatively permeable formation.

[0304]FIG. 123 depicts an embodiment of a Fischer-Tropsch process usingsynthesis gas produced from a relatively permeable formation.

[0305]FIG. 124 depicts an embodiment of a Shell Middle Distillatesprocess using synthesis gas produced from a relatively permeableformation.

[0306]FIG. 125 depicts an embodiment of a catalytic methanation processusing synthesis gas produced from a relatively permeable formation.

[0307]FIG. 126 depicts an embodiment of production of ammonia and ureausing synthesis gas produced from a relatively permeable formation.

[0308]FIG. 127 depicts an embodiment of production of ammonia and ureausing synthesis gas produced from a relatively permeable formation.

[0309]FIG. 128 depicts an embodiment of preparation of a feed stream foran ammonia and urea process.

[0310]FIG. 129 depicts an embodiment for treating a relatively permeableformation.

[0311]FIG. 130 depicts an embodiment for treating a relatively permeableformation.

[0312]FIG. 131 depicts an embodiment of heat sources in a relativelypermeable formation.

[0313]FIG. 132 depicts an embodiment of heat sources in a relativelypermeable formation.

[0314]FIG. 133 depicts an embodiment for treating a relatively permeableformation.

[0315]FIG. 134 depicts an embodiment for treating a relatively permeableformation.

[0316]FIG. 135 depicts an embodiment for treating a relatively permeableformation.

[0317]FIG. 136 depicts an embodiment of a heater well with selectiveheating.

[0318]FIG. 137 depicts a cross-sectional representation of an embodimentfor treating a formation with multiple heating sections.

[0319]FIG. 138 depicts an end view schematic of an embodiment fortreating a relatively permeable formation using a combination ofproducer and heater wells in the formation.

[0320]FIG. 139 depicts a side view schematic of the embodiment depictedin FIG. 138.

[0321]FIG. 140 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0322]FIG. 141 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0323]FIG. 142 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0324]FIG. 143 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0325]FIG. 144 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0326]FIG. 145 depicts a cross-sectional representation of an embodimentfor treating a relatively permeable formation.

[0327]FIG. 146 depicts a cross-sectional representation of an embodimentof production well placed in a formation.

[0328]FIG. 147 depicts linear relationships between total mass recoveryversus API gravity for three different tar sand formations.

[0329]FIG. 148 depicts schematic of an embodiment of a relativelypermeable formation used to produce a first mixture that is blended witha second mixture.

[0330]FIG. 149 depicts asphaltene content (on a whole oil basis) in ablend versus percent blending agent.

[0331]FIG. 150 depicts SARA results (saturate/aromatic ratio versusasphaltene/resin ratio) for several blends.

[0332]FIG. 151 illustrates near infrared transmittance versus volume ofn-heptane added to a first mixture.

[0333]FIG. 152 illustrates near infrared transmittance versus volume ofn-heptane added to a second mixture.

[0334]FIG. 153 illustrates near infrared transmittance versus volume ofn-heptane added to a third mixture.

[0335]FIG. 154 depicts changes in density with increasing temperaturefor several mixtures.

[0336]FIG. 155 depicts changes in viscosity with increasing temperaturefor several mixtures.

[0337]FIG. 156 depicts an embodiment of a heat source and productionwell pattern.

[0338]FIG. 157 depicts an embodiment of a heat source and productionwell pattern.

[0339]FIG. 158 depicts an embodiment of a heat source and productionwell pattern.

[0340]FIG. 159 depicts an embodiment of a heat source and productionwell pattern.

[0341]FIG. 160 depicts an embodiment of a heat source and productionwell pattern.

[0342]FIG. 161 depicts an embodiment of a heat source and productionwell pattern.

[0343]FIG. 162 depicts an embodiment of a heat source and productionwell pattern.

[0344]FIG. 163 depicts an embodiment of a heat source and productionwell pattern.

[0345]FIG. 164 depicts an embodiment of a heat source and productionwell pattern.

[0346]FIG. 165 depicts an embodiment of a heat source and productionwell pattern.

[0347]FIG. 166 depicts an embodiment of a heat source and productionwell pattern.

[0348]FIG. 167 depicts an embodiment of a heat source and productionwell pattern.

[0349]FIG. 168 depicts an embodiment of a heat source and productionwell pattern.

[0350]FIG. 169 depicts an embodiment of a square pattern of heat sourcesand production wells.

[0351]FIG. 170 depicts an embodiment of a heat source and productionwell pattern.

[0352]FIG. 171 depicts an embodiment of a triangular pattern of heatsources.

[0353]FIG. 172 depicts an embodiment of a square pattern of heatsources.

[0354]FIG. 173 depicts an embodiment of a hexagonal pattern of heatsources.

[0355]FIG. 174 depicts an embodiment of a 12 to 1 pattern of heatsources.

[0356]FIG. 175 depicts an embodiment of surface facilities for treatinga formation fluid.

[0357]FIG. 176 depicts an embodiment of a catalytic flamelessdistributed combustor.

[0358]FIG. 177 depicts an embodiment of surface facilities for treatinga formation fluid.

[0359]FIG. 178 depicts a temperature profile for a triangular pattern ofheat sources.

[0360]FIG. 179 depicts a temperature profile for a square pattern ofheat sources.

[0361]FIG. 180 depicts a temperature profile for a hexagonal pattern ofheat sources.

[0362]FIG. 181 depicts a comparison plot between the average patterntemperature and temperatures at the coldest spots for various patternsof heat sources.

[0363]FIG. 182 depicts a comparison plot between the average patterntemperature and temperatures at various spots within triangular andhexagonal patterns of heat sources.

[0364]FIG. 183 depicts a comparison plot between the average patterntemperature and temperatures at various spots within a square pattern ofheat sources.

[0365]FIG. 184 depicts a comparison plot between temperatures at thecoldest spots of various pattern of heat sources.

[0366]FIG. 185 depicts in situ temperature profiles for electricalresistance heaters and natural distributed combustion heaters.

[0367]FIG. 186 depicts extension of a reaction zone in a heatedformation over time.

[0368]FIG. 187 depicts the ratio of conductive heat transfer toradiative heat transfer in a formation.

[0369]FIG. 188 depicts the ratio of conductive heat transfer toradiative heat transfer in a formation.

[0370]FIG. 189 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0371]FIG. 190 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0372]FIG. 191 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0373]FIG. 192 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0374]FIG. 193 depicts a retort and collection system.

[0375]FIG. 194 depicts an embodiment of an apparatus for a drumexperiment.

[0376]FIG. 195 depicts locations of heat sources and wells in anexperimental field test.

[0377]FIG. 196 depicts a cross-sectional representation of the in situexperimental field test.

[0378]FIG. 197 depicts temperature versus time in the experimental fieldtest.

[0379]FIG. 198 depicts temperature versus time in the experimental fieldtest.

[0380]FIG. 199 depicts volatiles produced from a coal formation in theexperimental field test versus cumulative energy content.

[0381]FIG. 200 depicts volume of oil produced from a coal formation inthe experimental field test as a function of energy input.

[0382]FIG. 201 depicts synthesis gas production from the coal formationin the experimental field test versus the total water inflow.

[0383]FIG. 202 depicts additional synthesis gas production from the coalformation in the experimental field test due to injected steam.

[0384]FIG. 203 depicts the effect of methane injection into a heatedformation.

[0385]FIG. 204 depicts the effect of ethane injection into a heatedformation.

[0386]FIG. 205 depicts the effect of propane injection into a heatedformation.

[0387]FIG. 206 depicts the effect of butane injection into a heatedformation.

[0388]FIG. 207 depicts composition of gas produced from a formationversus time.

[0389]FIG. 208 depicts synthesis gas conversion versus time.

[0390]FIG. 209 depicts calculated equilibrium gas dry mole fractions fora reaction of coal with water.

[0391]FIG. 210 depicts calculated equilibrium gas wet mole fractions fora reaction of coal with water.

[0392]FIG. 211 depicts a plot of cumulative adsorbed methane and carbondioxide versus pressure in a coal formation.

[0393]FIG. 212 depicts pressure at a wellhead as a function of time froma numerical simulation.

[0394]FIG. 213 depicts production rate of carbon dioxide and methane asa function of time from a numerical simulation.

[0395]FIG. 214 depicts cumulative methane produced and net carbondioxide injected as a function of time from a numerical simulation.

[0396]FIG. 215 depicts pressure at wellheads as a function of time froma numerical simulation.

[0397]FIG. 216 depicts production rate of carbon dioxide as a functionof time from a numerical simulation.

[0398]FIG. 217 depicts cumulative net carbon dioxide injected as afunction of time from a numerical simulation.

[0399]FIG. 218 depicts weight percentages of carbon compounds versuscarbon number produced from a relatively permeable formation.

[0400]FIG. 219 depicts weight percentages of carbon compounds producedfrom a relatively permeable formation for various pyrolysis heatingrates and pressures.

[0401]FIG. 220 depicts H₂ mole percent in gases produced from heavyhydrocarbon drum experiments.

[0402]FIG. 221 depicts API gravity of liquids produced from heavyhydrocarbon drum experiments.

[0403]FIG. 222 depicts percentage of hydrocarbon fluid having carbonnumbers greater than 24 as a function of pressure and temperature foroil produced from a retort experiment.

[0404]FIG. 223 illustrates oil quality produced from a tar sandsformation as a function of pressure and temperature in a retortexperiment.

[0405]FIG. 224 illustrates an ethene to ethane ratio produced from a tarsands formation as a function of pressure and temperature in a retortexperiment.

[0406]FIG. 225 depicts the dependence of yield of equivalent liquidsproduced from a tar sands formation as a function of temperature andpressure in a retort experiment.

[0407]FIG. 226 illustrates a plot of percentage oil recovery versustemperature for a laboratory experiment and a simulation.

[0408]FIG. 227 depicts temperature versus time for a laboratoryexperiment and a simulation.

[0409]FIG. 228 depicts a plot of cumulative oil production versus timein a relatively permeable formation.

[0410]FIG. 229 depicts ratio of heat content of fluids produced from arelatively permeable formation to heat input versus time.

[0411]FIG. 230 depicts numerical simulation data of weight percentageversus carbon number for a relatively permeable formation.

[0412]FIG. 231 illustrates percentage cumulative oil recovery versustime for a simulation using horizontal heaters.

[0413]FIG. 232 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons in a simulation.

[0414]FIG. 233 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons with production inhibited for thefirst 500 days of heating in a simulation.

[0415]FIG. 234 depicts average pressure in a formation versus time in asimulation.

[0416]FIG. 235 illustrates cumulative oil production versus time for avertical producer and a horizontal producer in a simulation.

[0417]FIG. 236 illustrates percentage cumulative oil recovery versustime for three different horizontal producer well locations in asimulation.

[0418]FIG. 237 illustrates production rate versus time for heavyhydrocarbons and light hydrocarbons for middle and bottom producerlocations in a simulation.

[0419]FIG. 238 illustrates percentage cumulative oil recovery versustime in a simulation.

[0420]FIG. 239 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons in a simulation.

[0421]FIG. 240 illustrates a pattern of heater/producer wells used toheat a relatively permeable formation in a simulation.

[0422]FIG. 241 illustrates a pattern of heater/producer wells used inthe simulation with three heater/producer wells, a cold producer well,and three heater wells used to heat a relatively permeable formation ina simulation.

[0423]FIG. 242 illustrates a pattern of six heater wells and a coldproducer well used in a simulation.

[0424]FIG. 243 illustrates a plot of oil production versus time for thesimulation with the well pattern depicted in FIG. 240.

[0425]FIG. 244 illustrates a plot of oil production versus time for thesimulation with the well pattern depicted in FIG. 241.

[0426]FIG. 245 illustrates a plot of oil production versus time for thesimulation with the well pattern depicted in FIG. 242.

[0427]FIG. 246 illustrates gas production and water production versustime for the simulation with the well pattern depicted in FIG. 240.

[0428]FIG. 247 illustrates gas production and water production versustime for the simulation with the well pattern depicted in FIG. 241.

[0429]FIG. 248 illustrates gas production and water production versustime for the simulation with the well pattern depicted in FIG. 242.

[0430]FIG. 249 illustrates an energy ratio versus time for thesimulation with the well pattern depicted in FIG. 240.

[0431]FIG. 250 illustrates an energy ratio versus time for thesimulation with the well pattern depicted in FIG. 241.

[0432]FIG. 251 illustrates an energy ratio versus time for thesimulation with the well pattern depicted in FIG. 242.

[0433]FIG. 252 illustrates an average API gravity of produced fluidversus time for the simulations with the well patterns depicted in FIGS.240-242.

[0434]FIG. 253 depicts an heater well pattern used in a 3-D STARSsimulation.

[0435]FIG. 254 illustrates an energy out/energy in ratio versus time forproduction through a middle producer location in a simulation.

[0436]FIG. 255 illustrates percentage cumulative oil recovery versustime for production using a middle producer location and a bottomproducer location in a simulation.

[0437]FIG. 256 illustrates cumulative oil production versus time using amiddle producer location in a simulation.

[0438]FIG. 257 illustrates API gravity of oil produced and oilproduction rate for heavy hydrocarbons and light hydrocarbons for amiddle producer location in a simulation.

[0439]FIG. 258 illustrates cumulative oil production versus time for abottom producer location in a simulation.

[0440]FIG. 259 illustrates API gravity of oil produced and oilproduction rate for heavy hydrocarbons and light hydrocarbons for abottom producer location in a simulation.

[0441]FIG. 260 illustrates cumulative oil produced versus temperaturefor lab pyrolysis experiments and for a simulation.

[0442]FIG. 261 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons produced through a middle producerlocation in a simulation.

[0443]FIG. 262 illustrates cumulative oil production versus time for awider horizontal heater spacing with production through a middleproducer location in a simulation.

[0444]FIG. 263 depicts heater well pattern used in a 3-D STARSsimulation.

[0445]FIG. 264 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons produced through a production welllocated in the middle of the formation in a simulation.

[0446]FIG. 265 illustrates cumulative oil production versus time for atriangular heater pattern used in a simulation.

[0447]FIG. 266 illustrates a pattern of wells used for a simulation.

[0448]FIG. 267 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons for production using a bottomproduction well in a simulation.

[0449]FIG. 268 illustrates cumulative oil production versus time forproduction through a bottom production well in a simulation.

[0450]FIG. 269 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons for production using a middleproduction well in a simulation.

[0451]FIG. 270 illustrates cumulative oil production versus time forproduction through a middle production well in a simulation.

[0452]FIG. 271 illustrates oil production rate versus time for heavyhydrocarbon production and light hydrocarbon production for productionusing a top production well in a simulation.

[0453]FIG. 272 illustrates cumulative oil production versus time forproduction through a top production well in a simulation.

[0454]FIG. 273 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons produced in a simulation.

[0455]FIG. 274 depicts an embodiment of a well pattern used in asimulation.

[0456]FIG. 275 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons for three production wells in asimulation.

[0457]FIG. 276 and FIG. 277 illustrate coke deposition near heaterwells.

[0458]FIG. 278 depicts a large pattern of heater and producer wells usedin a 3-D STARS simulation of an in situ process for a tar sandsformation.

[0459]FIG. 279 depicts net heater output versus time for the simulationwith the well pattern depicted in FIG. 278.

[0460]FIG. 280 depicts average pressure and average temperature versustime in a section of the formation for the simulation with the wellpattern depicted in FIG. 278.

[0461]FIG. 281 depicts oil production rate versus time as calculated inthe simulation with the well pattern depicted in FIG. 278.

[0462]FIG. 282 depicts cumulative oil production versus time ascalculated in the simulation with the well pattern depicted in FIG. 278.

[0463]FIG. 283 depicts gas production rate versus time as calculated inthe simulation with the well pattern depicted in FIG. 278.

[0464]FIG. 284 depicts cumulative gas production versus time ascalculated in the simulation with the well pattern depicted in FIG. 278.

[0465]FIG. 285 depicts energy ratio versus time as calculated in thesimulation with the well pattern depicted in FIG. 278.

[0466]FIG. 286 depicts average oil density versus time for thesimulation with the well pattern depicted in FIG. 278.

[0467]FIG. 287 depicts a schematic of a surface treatment configurationthat separates formation fluid as it is being produced from a formation.

[0468]FIG. 288 depicts a schematic of a surface facility configurationthat heats a fluid for use in an in situ treatment process and/or asurface facility configuration.

[0469]FIG. 289 depicts a schematic of an embodiment of a fractionatorthat separates component streams from a synthetic condensate.

[0470]FIG. 290 depicts a schematic of an embodiment of a series ofseparating units used to separate component streams from formationfluid.

[0471]FIG. 291 depicts a schematic an embodiment of a series ofseparating units used to separate formation fluid into fractions.

[0472]FIG. 292 depicts a schematic of an embodiment of a surfacetreatment configuration used to reactively distill a syntheticcondensate.

[0473]FIG. 293 depicts a schematic of an embodiment of a surfacetreatment configuration that separates formation fluid throughcondensation.

[0474]FIG. 294 depicts a schematic of an embodiment of a surfacetreatment configuration that hydrotreats untreated formation fluid.

[0475]FIG. 295 depicts a schematic of an embodiment of a surfacetreatment configuration that converts formation fluid into olefins.

[0476]FIG. 296 depicts a schematic of an embodiment of a surfacetreatment configuration that removes a component and converts formationfluid into olefins.

[0477]FIG. 297 depicts a schematic of an embodiment of a surfacetreatment configuration that converts formation fluid into olefins usinga heating unit and a quenching unit.

[0478]FIG. 298 depicts a schematic of an embodiment of a surfacetreatment configuration that separates ammonia and hydrogen sulfide fromwater produced in the formation.

[0479]FIG. 299 depicts a schematic of an embodiment of a surfacetreatment configuration used to produce and separate ammonia.

[0480]FIG. 300 depicts a schematic of an embodiment of a surfacetreatment configuration that separates ammonia and hydrogen sulfide fromwater produced in the formation.

[0481]FIG. 301 depicts a schematic of an embodiment of a surfacetreatment configuration that produces ammonia on site.

[0482]FIG. 302 depicts a schematic of an embodiment of a surfacetreatment configuration used for the synthesis of urea.

[0483]FIG. 303 depicts a schematic of an embodiment of a surfacetreatment configuration that synthesizes ammonium sulfate.

[0484]FIG. 304 depicts a schematic of an embodiment of a surfacetreatment configuration used to separate BTEX compounds from formationfluid.

[0485]FIG. 305 depicts a schematic of an embodiment of a surfacetreatment configuration used to recover BTEX compounds from a naphthafraction.

[0486]FIG. 306 depicts a schematic of an embodiment of a surfacetreatment configuration that separates a component from a heart cut.

[0487]FIG. 307 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers.

[0488]FIG. 308 depicts a side representation of an embodiment of an insitu conversion process system used to treat a thin rich formation.

[0489]FIG. 309 depicts a side representation of an embodiment of an insitu conversion process system used to treat a thin rich formation.

[0490]FIG. 310 depicts a side representation of an embodiment of an insitu conversion process system.

[0491]FIG. 311 depicts a side representation of an embodiment of an insitu conversion process system with an installed upper perimeter barrierand an installed lower perimeter barrier.

[0492]FIG. 312 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers having arced portions,wherein the centers of the arced portions are in an equilateral trianglepattern.

[0493]FIG. 313 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers having arced portions,wherein the centers of the arced portions are in a square pattern.

[0494]FIG. 314 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers radially positioned arounda central point.

[0495]FIG. 315 depicts a plan view representation of a portion of atreatment area defined by a double ring of freeze wells.

[0496]FIG. 316 depicts a side representation of a freeze well that isdirectionally drilled in a formation so that the freeze well enters theformation in a first location and exits the formation in a secondlocation.

[0497]FIG. 317 depicts a side representation of freeze wells that form abarrier along sides and ends of a dipping hydrocarbon containing layerin a formation.

[0498]FIG. 318 depicts a representation of an embodiment of a freezewell and an embodiment of a heat source that may be used during an insitu conversion process.

[0499]FIG. 319 depicts an embodiment of a batch operated freeze well.

[0500]FIG. 320 depicts an embodiment of a batch operated freeze wellhaving an open wellbore portion.

[0501]FIG. 321 depicts a plan view representation of a circulated fluidrefrigeration system.

[0502]FIG. 322 shows simulation results as a plot of time to reduce atemperature midway between two freeze wells versus well spacing.

[0503]FIG. 323 depicts an embodiment of a freeze well for a circulatedliquid refrigeration system, wherein a cutaway view of the freeze wellis represented below ground surface.

[0504]FIG. 324 depicts an embodiment of a freeze well for a circulatedliquid refrigeration system.

[0505]FIG. 325 depicts an embodiment of a freeze well for a circulatedliquid refrigeration system.

[0506]FIG. 326 depicts results of a simulation for Green River oil shalepresented as temperature versus time for a formation cooled with arefrigerant.

[0507]FIG. 327 depicts a plan view representation of low temperaturezones formed by freeze wells placed in a formation through which fluidflows slowly enough to allow for formation of an interconnected lowtemperature zone.

[0508]FIG. 328 depicts a plan view representation of low temperaturezones formed by freeze wells placed in a formation through which fluidflows at too high a flow rate to allow for formation of aninterconnected low temperature zone.

[0509]FIG. 329 depicts thermal simulation results of a heat sourcesurrounded by a ring of freeze wells.

[0510]FIG. 330 depicts a representation of an embodiment of a groundcover.

[0511]FIG. 331 depicts an embodiment of a treatment area surrounded by aring of dewatering wells.

[0512]FIG. 332 depicts an embodiment of a treatment area surrounded bytwo rings of dewatering wells.

[0513]FIG. 333 depicts an embodiment of a treatment area surrounded bythree rings of dewatering wells.

[0514]FIG. 334 illustrates a schematic of an embodiment of an injectionwellbore and a production wellbore.

[0515]FIG. 335 depicts an embodiment of a remediation process used totreat a treatment area.

[0516]FIG. 336 depicts an embodiment of a heated formation used as aradial distillation column.

[0517]FIG. 337 depicts an embodiment of a heated formation used forseparation of hydrocarbons and contaminants.

[0518]FIG. 338 depicts an embodiment for recovering heat from a heatedformation and transferring the heat to an above-ground processing unit.

[0519]FIG. 339 depicts an embodiment for recovering heat from oneformation and providing heat to another formation with an intermediateproduction step.

[0520]FIG. 340 depicts an embodiment for recovering heat from oneformation and providing heat to another formation in situ.

[0521]FIG. 341 depicts an embodiment of a region of reaction within aheated formation.

[0522]FIG. 342 depicts an embodiment of a conduit placed within a heatedformation.

[0523]FIG. 343 depicts an embodiment of a U-shaped conduit placed withina heated formation.

[0524]FIG. 344 depicts an embodiment for sequestration of carbon dioxidein a heated formation.

[0525]FIG. 345 depicts an embodiment for solution mining a formation.

[0526]FIG. 346 is a flow chart illustrating options for produced fluidsfrom a shut-in formation.

[0527]FIG. 347 illustrates a schematic of an embodiment of an injectionwellbore and a production wellbore.

[0528]FIG. 348 illustrates a cross-sectional representation of in situtreatment of a formation with steam injection according to oneembodiment.

[0529]FIG. 349 illustrates a cross-sectional representation of in situtreatment of a formation with steam injection according to oneembodiment.

[0530]FIG. 350 illustrates a cross-sectional representation of in situtreatment of a formation with steam injection according to oneembodiment.

[0531] While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION OF THE INVENTION

[0532] The following description generally relates to systems andmethods for treating a relatively permeable formation. Such formationsmay be treated to yield relatively high quality hydrocarbon products,hydrogen, and other products.

[0533] “Hydrocarbons” are organic material with molecular structurescontaining carbon and hydrogen. Hydrocarbons may also include otherelements, such as, but not limited to, halogens, metallic elements,nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are notlimited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes,and asphaltites. Hydrocarbons may be located within or adjacent tomineral matrices within the earth. Matrices may include, but are notlimited to, sedimentary rock, sands, silicilytes, carbonates,diatomites, and other porous media. “Hydrocarbon fluids” are fluids thatinclude hydrocarbons. Hydrocarbon fluids may include, entrain, or beentrained in non-hydrocarbon fluids (e.g., hydrogen (“H₂”), nitrogen(“N₂”), carbon monoxide, carbon dioxide, hydrogen sulfide, water, andammonia).

[0534] A “formation” includes one or more hydrocarbon containing layers,one or more non-hydrocarbon layers, an overburden, and/or anunderburden. An “overburden” and/or an “underburden” includes one ormore different types of impermeable materials. For example, overburdenand/or underburden may include rock, shale, mudstone, or wet/tightcarbonate (i.e., an impermeable carbonate without hydrocarbons). In someembodiments of in situ conversion processes, an overburden and/or anunderburden may include a hydrocarbon containing layer or hydrocarboncontaining layers that are relatively impermeable and are not subjectedto temperatures during in situ conversion processing that results insignificant characteristic changes of the hydrocarbon containing layersof the overburden and/or underburden. For example, an underburden maycontain shale or mudstone. In some cases, the overburden and/orunderburden may be somewhat permeable.

[0535] The terms “formation fluids” and “produced fluids” refer tofluids removed from a relatively permeable formation and may includepyrolyzation fluid, synthesis gas, mobilized hydrocarbon, and water(steam). The term “mobilized fluid” refers to fluids within theformation that are able to flow because of thermal treatment of theformation. Formation fluids may include hydrocarbon fluids as well asnon-hydrocarbon fluids.

[0536] “Carbon number” refers to a number of carbon atoms within amolecule. A hydrocarbon fluid may include various hydrocarbons havingvarying numbers of carbon atoms. The hydrocarbon fluid may be describedby a carbon number distribution. Carbon numbers and/or carbon numberdistributions may be determined by true boiling point distributionand/or gas-liquid chromatography.

[0537] A “heat source” is any system for providing heat to at least aportion of a formation substantially by conductive and/or radiative heattransfer. For example, a heat source may include electric heaters suchas an insulated conductor, an elongated member, and a conductor disposedwithin a conduit, as described in embodiments herein. A heat source mayalso include heat sources that generate heat by burning a fuel externalto or within a formation, such as surface burners, downhole gas burners,flameless distributed combustors, and natural distributed combustors, asdescribed in embodiments herein. In addition, it is envisioned that insome embodiments heat provided to or generated in one or more heatsources may by supplied by other sources of energy. The other sources ofenergy may directly heat a formation, or the energy may be applied to atransfer media that directly or indirectly heats the formation. It is tobe understood that one or more heat sources that are applying heat to aformation may use different sources of energy. Thus, for example, for agiven formation some heat sources may supply heat from electricresistance heaters, some heat sources may provide heat from combustion,and some heat sources may provide heat from one or more other energysources (e.g., chemical reactions, solar energy, wind energy, biomass,or other sources of renewable energy). A chemical reaction may includean exothermic reaction (e.g., an oxidation reaction). A heat source mayalso include a heater that may provide heat to a zone proximate and/orsurrounding a heating location such as a heater well.

[0538] A “heater” is any system for generating heat in a well or a nearwellbore region. Heaters may be, but are not limited to, electricheaters, burners, combustors (e.g., natural distributed combustors) thatreact with material in or produced from a formation, and/or combinationsthereof. A “unit of heat sources” refers to a number of heat sourcesthat form a template that is repeated to create a pattern of heatsources within a formation.

[0539] The term “wellbore” refers to a hole in a formation made bydrilling or insertion of a conduit into the formation. A wellbore mayhave a substantially circular cross section, or other cross-sectionalshapes (e.g., circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes). As used herein, the terms “well” and“opening,” when referring to an opening in the formation may be usedinterchangeably with the term “wellbore.”

[0540] “Natural distributed combustor” refers to a heater that uses anoxidant to oxidize at least a portion of the carbon in the formation togenerate heat, and wherein the oxidation takes place in a vicinityproximate a wellbore. Most of the combustion products produced in thenatural distributed combustor are removed through the wellbore.

[0541] “Orifices,” refers to openings (e.g., openings in conduits)having a wide variety of sizes and cross-sectional shapes including, butnot limited to, circles, ovals, squares, rectangles, triangles, slits,or other regular or irregular shapes.

[0542] “Reaction zone” refers to a volume of a relatively permeableformation that is subjected to a chemical reaction such as an oxidationreaction.

[0543] “Insulated conductor” refers to any elongated material that isable to conduct electricity and that is covered, in whole or in part, byan electrically insulating material. The term “self-controls” refers tocontrolling an output of a heater without external control of any type.

[0544] “Pyrolysis” is the breaking of chemical bonds due to theapplication of heat. For example, pyrolysis may include transforming acompound into one or more other substances by heat alone. Heat may betransferred to a section of the formation to cause pyrolysis.

[0545] “Pyrolyzation fluids” or “pyrolysis products” refers to fluidproduced substantially during pyrolysis of hydrocarbons. Fluid producedby pyrolysis reactions may mix with other fluids in a formation. Themixture would be considered pyrolyzation fluid or pyrolyzation product.As used herein, “pyrolysis zone” refers to a volume of a formation(e.g., a relatively permeable formation such as a tar sands formation)that is reacted or reacting to form a pyrolyzation fluid.

[0546] “Cracking” refers to a process involving decomposition andmolecular recombination of organic compounds to produce a greater numberof molecules than were initially present. In cracking, a series ofreactions take place accompanied by a transfer of hydrogen atoms betweenmolecules. For example, naphtha may undergo a thermal cracking reactionto form ethene and H₂.

[0547] “Superposition of heat” refers to providing heat from two or moreheat sources to a selected section of a formation such that thetemperature of the formation at least at one location between the heatsources is influenced by the heat sources.

[0548] “Fingering” refers to injected fluids bypassing portions of aformation because of variations in transport characteristics of theformation (e.g., permeability or porosity).

[0549] “Thermal conductivity” is a property of a material that describesthe rate at which heat flows, in steady state, between two surfaces ofthe material for a given temperature difference between the twosurfaces.

[0550] “Fluid pressure” is a pressure generated by a fluid within aformation. “Lithostatic pressure” (sometimes referred to as “lithostaticstress”) is a pressure within a formation equal to a weight per unitarea of an overlying rock mass. “Hydrostatic pressure” is a pressurewithin a formation exerted by a column of water.

[0551] “Condensable hydrocarbons” are hydrocarbons that condense at 25°C. at one atmosphere absolute pressure. Condensable hydrocarbons mayinclude a mixture of hydrocarbons having carbon numbers greater than 4.“Non-condensable hydrocarbons” are hydrocarbons that do not condense at25° C. and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

[0552] “Olefins” are molecules that include unsaturated hydrocarbonshaving one or more non-aromatic carbon-to-carbon double bonds.

[0553] “Urea” describes a compound represented by the molecular formulaof NH₂—CO—NH₂. Urea may be used as a fertilizer.

[0554] “Synthesis gas” is a mixture including hydrogen and carbonmonoxide used for synthesizing a wide range of compounds. Additionalcomponents of synthesis gas may include water, carbon dioxide, nitrogen,methane, and other gases. Synthesis gas may be generated by a variety ofprocesses and feedstocks.

[0555] “Reforming” is a reaction of hydrocarbons (such as methane ornaphtha) with steam to produce CO and H₂ as major products. Generally,it is conducted in the presence of a catalyst, although it can beperformed thermally without the presence of a catalyst.

[0556] “Sequestration” refers to storing a gas that is a by-product of aprocess rather than venting the gas to the atmosphere.

[0557] “Dipping” refers to a formation that slopes downward or inclinesfrom a plane parallel to the earth's surface, assuming the plane is flat(i.e., a “horizontal” plane). A “dip” is an angle that a stratum orsimilar feature makes with a horizontal plane. A “steeply dipping”relatively permeable formation refers to a relatively permeableformation lying at an angle of at least 20° from a horizontal plane.“Down dip” refers to downward along a direction parallel to a dip in aformation. “Up dip” refers to upward along a direction parallel to a dipof a formation. “Strike” refers to the course or bearing of hydrocarbonmaterial that is normal to the direction of dip.

[0558] “Subsidence” is a downward movement of a portion of a formationrelative to an initial elevation of the surface.

[0559] “Thickness” of a layer refers to the thickness of a cross sectionof a layer, wherein the cross section is normal to a face of the layer.

[0560] “Coring” is a process that generally includes drilling a holeinto a formation and removing a substantially solid mass of theformation from the hole.

[0561] A “surface unit” is an ex situ treatment unit.

[0562] “Middle distillates” refers to hydrocarbon mixtures with aboiling point range that corresponds substantially with that of keroseneand gas oil fractions obtained in a conventional atmosphericdistillation of crude oil material. The middle distillate boiling pointrange may include temperatures between about 150° C. and about 360° C.,with a fraction boiling point between about 200° C. and about 360° C.Middle distillates may be referred to as gas oil.

[0563] A “boiling point cut” is a hydrocarbon liquid fraction that maybe separated from hydrocarbon liquids when the hydrocarbon liquids areheated to a boiling point range of the fraction.

[0564] “Selected mobilized section” refers to a section of a formationthat is at an average temperature within a mobilization temperaturerange. “Selected pyrolyzation section” refers to a section of aformation (e.g., a relatively permeable formation such as a tar sandsformation) that is at an average temperature within a pyrolyzationtemperature range.

[0565] “Enriched air” refers to air having a larger mole fraction ofoxygen than air in the atmosphere. Enrichment of air is typically doneto increase its combustion-supporting ability.

[0566] “Heavy hydrocarbons” are viscous hydrocarbon fluids. Heavyhydrocarbons may include highly viscous hydrocarbon fluids such as heavyoil, tar, and/or asphalt. Heavy hydrocarbons may include carbon andhydrogen, as well as smaller concentrations of sulfur, oxygen, andnitrogen. Additional elements may also be present in heavy hydrocarbonsin trace amounts. Heavy hydrocarbons may be classified by API gravity.Heavy hydrocarbons generally have an API gravity below about 20°. Heavyoil, for example, generally has an API gravity of about 10-20°, whereastar generally has an API gravity below about 100. The viscosity of heavyhydrocarbons is generally greater than about 100 centipoise at 15° C.Heavy hydrocarbons may also include aromatics or other complex ringhydrocarbons.

[0567] Heavy hydrocarbons may be found in a relatively permeableformation. The relatively permeable formation may include heavyhydrocarbons entrained in, for example, sand or carbonate. “Relativelypermeable” is defined, with respect to formations or portions thereof,as an average permeability of 10 millidarcy or more (e.g., 10 or 100millidarcy).

[0568] “Relatively low permeability” is defined, with respect toformations or portions thereof, as an average permeability of less thanabout 10 millidarcy. One darcy is equal to about 0.99 squaremicrometers. An impermeable layer generally has a permeability of lessthan about 0.1 millidarcy.

[0569] “Tar” is a viscous hydrocarbon that generally has a viscositygreater than about 10,000 centipoise at 15° C. The specific gravity oftar generally is greater than 1.000. Tar may have an API gravity lessthan 10°.

[0570] A “tar sands formation” is a formation in which hydrocarbons arepredominantly present in the form of heavy hydrocarbons and/or tarentrained in a mineral grain framework or other host lithology (e.g.,sand or carbonate).

[0571] In some cases, a portion or all of a hydrocarbon portion of arelatively permeable formation may be predominantly heavy hydrocarbonsand/or tar with no supporting mineral grain framework and only floating(or no) mineral matter (e.g., asphalt lakes).

[0572] Certain types of formations that include heavy hydrocarbons mayalso be, but are not limited to, natural mineral waxes (e.g.,ozocerite), or natural asphaltites (e.g., gilsonite, albertite,impsonite, wurtzilite, grahamite, and glance pitch). “Natural mineralwaxes” typically occur in substantially tubular veins that may beseveral meters wide, several kilometers long, and hundreds of metersdeep. “Natural asphaltites” include solid hydrocarbons of an aromaticcomposition and typically occur in large veins. In situ recovery ofhydrocarbons from formations such as natural mineral waxes and naturalasphaltites may include melting to form liquid hydrocarbons and/orsolution mining of hydrocarbons from the formations.

[0573] “Upgrade” refers to increasing the quality of hydrocarbons. Forexample, upgrading heavy hydrocarbons may result in an increase in theAPI gravity of the heavy hydrocarbons.

[0574] “Off peak” times refers to times of operation when utility energyis less commonly used and, therefore, less expensive.

[0575] “Low viscosity zone” refers to a section of a formation where atleast a portion of the fluids are mobilized.

[0576] “Thermal fracture” refers to fractures created in a formationcaused by expansion or contraction of a formation and/or fluids withinthe formation, which is in turn caused by increasing/decreasing thetemperature of the formation and/or fluids within the formation, and/orby increasing/decreasing a pressure of fluids within the formation dueto heating.

[0577] “Vertical hydraulic fracture” refers to a fracture at leastpartially propagated along a vertical plane in a formation, wherein thefracture is created through injection of fluids into a formation.

[0578] Hydrocarbons in formations may be treated in various ways toproduce many different products. In certain embodiments, such formationsmay be treated in stages. FIG. 1 illustrates several stages of heating arelatively permeable formation. FIG. 1 also depicts an example of yield(barrels of oil equivalent per ton) (y axis) of formation fluids from arelatively permeable formation versus temperature (° C.) (x axis) of theformation.

[0579] Desorption of methane and vaporization of water occurs duringstage 1 heating. Heating of the formation through stage 1 may beperformed as quickly as possible. For example, when a relativelypermeable formation is initially heated, hydrocarbons in the formationmay desorb adsorbed methane. The desorbed methane may be produced fromthe formation. If the relatively permeable formation is heated further,water within the relatively permeable formation may be vaporized. Watermay occupy, in some relatively permeable formations, between about 10%to about 50% of the pore volume in the formation. In other formations,water may occupy larger or smaller portions of the pore volume. Watertypically is vaporized in a formation between about 160° C. and about285° C. for pressures of about 6 bars absolute to 70 bars absolute. Insome embodiments, the vaporized water may produce wettability changes inthe formation and/or increase formation pressure. The wettabilitychanges and/or increased pressure may affect pyrolysis reactions orother reactions in the formation. In certain embodiments, the vaporizedwater may be produced from the formation. In other embodiments, thevaporized water may be used for steam extraction and/or distillation inthe formation or outside the formation. Removing the water from andincreasing the pore volume in the formation may increase the storagespace for hydrocarbons within the pore volume.

[0580] After stage 1 heating, the formation may be heated further, suchthat a temperature within the formation reaches (at least) an initialpyrolyzation temperature (e.g., a temperature at the lower end of thetemperature range shown as stage 2). Hydrocarbons within the formationmay be pyrolyzed throughout stage 2. A pyrolysis temperature range mayvary depending on types of hydrocarbons within the formation. Apyrolysis temperature range may include temperatures between about 250°C. and about 900° C. A pyrolysis temperature range for producing desiredproducts may extend through only a portion of the total pyrolysistemperature range. In some embodiments, a pyrolysis temperature rangefor producing desired products may include temperatures between about250° C. to about 400° C. If a temperature of hydrocarbons in a formationis slowly raised through a temperature range from about 250° C. to about400° C., production of pyrolysis products may be substantially completewhen the temperature approaches 400° C. Heating the hydrocarbonformation with a plurality of heat sources may establish thermalgradients around the heat sources that slowly raise the temperature ofhydrocarbons in the formation through a pyrolysis temperature range.

[0581] In some in situ conversion embodiments, a temperature of thehydrocarbons to be subjected to pyrolysis may not be slowly increasedthroughout a temperature range from about 250° C. to about 400° C. Thehydrocarbons in the formation may be heated to a desired temperature(e.g., about 325° C.). Other temperatures may be selected as the desiredtemperature. Superposition of heat from heat sources may allow thedesired temperature to be relatively quickly and efficiently establishedin the formation. Energy input into the formation from the heat sourcesmay be adjusted to maintain the temperature in the formationsubstantially at the desired temperature. The hydrocarbons may bemaintained substantially at the desired temperature until pyrolysisdeclines such that production of desired formation fluids from theformation becomes uneconomical. Formation fluids including pyrolyzationfluids may be produced from the formation.

[0582] The pyrolyzation fluids may include, but are not limited to,hydrocarbons, hydrogen, carbon dioxide, carbon monoxide, hydrogensulfide, ammonia, nitrogen, water, and mixtures thereof. As thetemperature of the formation increases, the amount of condensablehydrocarbons in the produced formation fluid tends to decrease. At hightemperatures, the formation may produce mostly methane and/or hydrogen.If a relatively permeable formation is heated throughout an entirepyrolysis range, the formation may produce only small amounts ofhydrogen towards an upper limit of the pyrolysis range. After all of theavailable hydrogen is depleted, a minimal amount of fluid productionfrom the formation will typically occur.

[0583] After pyrolysis of hydrocarbons, a large amount of carbon andsome hydrogen may still be present in the formation. A significantportion of remaining carbon in the formation can be produced from theformation in the form of synthesis gas. Synthesis gas generation maytake place during stage 3 heating depicted in FIG. 1. Stage 3 mayinclude heating a relatively permeable formation to a temperaturesufficient to allow synthesis gas generation. For example, synthesis gasmay be produced within a temperature range from about 400° C. to about1200° C. The temperature of the formation when the synthesis gasgenerating fluid is introduced to the formation may determine thecomposition of synthesis gas produced within the formation. If asynthesis gas generating fluid is introduced into a formation at atemperature sufficient to allow synthesis gas generation, synthesis gasmay be generated within the formation. The generated synthesis gas maybe removed from the formation through a production well or productionwells. A large volume of synthesis gas may be produced during generationof synthesis gas.

[0584] Total energy content of fluids produced from a relativelypermeable formation may stay relatively constant throughout pyrolysisand synthesis gas generation. During pyrolysis at relatively lowformation temperatures, a significant portion of the produced fluid maybe condensable hydrocarbons that have a high energy content. At higherpyrolysis temperatures, however, less of the formation fluid may includecondensable hydrocarbons. More non-condensable formation fluids may beproduced from the formation. Energy content per unit volume of theproduced fluid may decline slightly during generation of predominantlynon-condensable formation fluids. During synthesis gas generation,energy content per unit volume of produced synthesis gas declinessignificantly compared to energy content of pyrolyzation fluid. Thevolume of the produced synthesis gas, however, will in many instancesincrease substantially, thereby compensating for the decreased energycontent.

[0585] A relatively permeable formation may have a number of propertiesthat depend on a composition of the hydrocarbons within the formation.Such properties may affect the composition and amount of products thatare produced from a relatively permeable formation during in situconversion. Properties of a relatively permeable formation may be usedto determine if and/or how a relatively permeable formation is to besubjected to in situ conversion.

[0586] Relatively permeable formations may be selected for in situconversion based on properties of at least a portion of the formation.For example, a formation may be selected based on richness, thickness,and/or depth (i.e., thickness of overburden) of the formation. Inaddition, the types of fluids producible from the formation may be afactor in the selection of a formation for in situ conversion. Incertain embodiments, the quality of the fluids to be produced may beassessed in advance of treatment. Assessment of the products that may beproduced from a formation may generate significant cost savings sinceonly formations that will produce desired products need to be subjectedto in situ conversion. Properties that may be used to assesshydrocarbons in a formation include, but are not limited to, an amountof hydrocarbon liquids that may be produced from the hydrocarbons, alikely API gravity of the produced hydrocarbon liquids, an amount ofhydrocarbon gas producible from the formation, and/or an amount ofcarbon dioxide and water that in situ conversion will generate.

[0587] In some in situ conversion embodiments, a relatively permeableformation may be selected for treatment based on a hydrogen contentwithin the hydrocarbons in the formation. For example, a method oftreating a relatively permeable formation may include selecting aportion of the relatively permeable formation for treatment havinghydrocarbons with a hydrogen content greater than about 3 weight %, 3.5weight %, or 4 weight % when measured on a dry, ash-free basis. Inaddition, a selected section of a relatively permeable formation mayinclude hydrocarbons with an atomic hydrogen to carbon ratio that fallswithin a range from about 0.5 to about 2, and in many instances fromabout 0.70 to about 1.65.

[0588] Hydrogen content of a relatively permeable formation maysignificantly influence a composition of hydrocarbon fluids produciblefrom the formation. Pyrolysis of hydrocarbons within heated portions ofthe formation may generate hydrocarbon fluids that include a double bondor a radical. Hydrogen within the formation may reduce the double bondto a single bond. Reaction of generated hydrocarbon fluids with eachother and/or with additional components in the formation may beinhibited. For example, reduction of a double bond of the generatedhydrocarbon fluids to a single bond may reduce polymerization of thegenerated hydrocarbons. Such polymerization may reduce the amount offluids produced and may reduce the quality of fluid produced from theformation.

[0589] Hydrogen within the formation may neutralize radicals in thegenerated hydrocarbon fluids. Hydrogen present in the formation mayinhibit reaction of hydrocarbon fragments by transforming thehydrocarbon fragments into relatively short chain hydrocarbon fluids.The hydrocarbon fluids may enter a vapor phase. Vapor phase hydrocarbonsmay move relatively easily through the formation to production wells.Increase in the hydrocarbon fluids in the vapor phase may significantlyreduce a potential for producing less desirable products within theselected section of the formation.

[0590] A lack of bound and free hydrogen in the formation may negativelyaffect the amount and quality of fluids that can be produced from theformation. If too little hydrogen is naturally present, then hydrogen orother reducing fluids may be added to the formation.

[0591] When heating a portion of a relatively permeable formation,oxygen within the portion may form carbon dioxide. A formation may bechosen and/or conditions in a formation may be adjusted to inhibitproduction of carbon dioxide and other oxides.

[0592] Heating a relatively permeable formation may include providing alarge amount of energy to heat sources located within the formation.Relatively permeable formations may also contain some water. Asignificant portion of energy initially provided to a formation may beused to heat water within the formation. An initial rate of temperatureincrease may be reduced by the presence of water in the formation.Excessive amounts of heat and/or time may be required to heat aformation having a high moisture content to a temperature sufficient topyrolyze hydrocarbons in the formation. In certain embodiments, watermay be inhibited from flowing into a formation subjected to in situconversion. A formation to be subjected to in situ conversion may have alow initial moisture content. The formation may have an initial moisturecontent that is less than about 15 weight %. Some formations that are tobe subjected to in situ conversion may have an initial moisture contentof less than about 10 weight %. Other formations that are to beprocessed using an in situ conversion process may have initial moisturecontents that are greater than about 15 weight %. Formations withinitial moisture contents above about 15 weight % may incur significantenergy costs to remove the water that is initially present in theformation during heating to pyrolysis temperatures.

[0593] A relatively permeable formation may be selected for treatmentbased on additional factors such as, but not limited to, thickness ofhydrocarbon containing layers within the formation, assessed liquidproduction content, location of the formation, and depth of hydrocarboncontaining layers. A relatively permeable formation may include multiplelayers. Such layers may include hydrocarbon containing layers, as wellas layers that are hydrocarbon free or have relatively low amounts ofhydrocarbons. Conditions during formation may determine the thickness ofhydrocarbon and non-hydrocarbon layers in a relatively permeableformation. A relatively permeable formation to be subjected to in situconversion will typically include at least one hydrocarbon containinglayer having a thickness sufficient for economical production offormation fluids. Richness of a hydrocarbon containing layer may be afactor used to determine if a formation will be treated by in situconversion. A thin and rich hydrocarbon layer may be able to producesignificantly more valuable hydrocarbons than a much thicker, less richhydrocarbon layer. Producing hydrocarbons from a formation that is boththick and rich is desirable.

[0594] Each hydrocarbon containing layer of a formation may have apotential formation fluid yield or richness. The richness of ahydrocarbon layer may vary in a hydrocarbon layer and between differenthydrocarbon layers in a formation. Richness may depend on many factorsincluding the conditions under which the hydrocarbon containing layerwas formed, an amount of hydrocarbons in the layer, and/or a compositionof hydrocarbons in the layer. Richness of a hydrocarbon layer may beestimated in various ways. For example, richness may be measured by aFischer Assay. The Fischer Assay is a standard method which involvesheating a sample of a hydrocarbon containing layer to approximately 500°C. in one hour, collecting products produced from the heated sample, andquantifying the amount of products produced. A sample of a hydrocarboncontaining layer may be obtained from a relatively permeable formationby a method such as coring or any other sample retrieval method.

[0595] An in situ conversion process may be used to treat formationswith hydrocarbon layers that have thicknesses greater than about 10 m.Thick formations may allow for placement of heat sources so thatsuperposition of heat from the heat sources efficiently heats theformation to a desired temperature. Formations having hydrocarbon layersthat are less than 10 m thick may also be treated using an in situconversion process. In some in situ conversion embodiments of thinhydrocarbon layer formations, heat sources may be inserted in oradjacent to the hydrocarbon layer along a length of the hydrocarbonlayer (e.g., with horizontal or directional drilling). Heat losses tolayers above and below the thin hydrocarbon layer or thin hydrocarbonlayers may be offset by an amount and/or quality of fluid produced fromthe formation.

[0596]FIG. 2 shows a schematic view of an embodiment of a portion of anin situ conversion system for treating a relatively permeable formation.Heat sources 100 may be placed within at least a portion of therelatively permeable formation. Heat sources 100 may include, forexample, electric heaters such as insulated conductors,conductor-in-conduit heaters, surface burners, flameless distributedcombustors, and/or natural distributed combustors. Heat sources 100 mayalso include other types of heaters. Heat sources 100 may provide heatto at least a portion of a relatively permeable formation. Energy may besupplied to the heat sources 100 through supply lines 102. The supplylines may be structurally different depending on the type of heat sourceor heat sources being used to heat the formation. Supply lines for heatsources may transmit electricity for electric heaters, may transportfuel for combustors, or may transport heat exchange fluid that iscirculated within the formation.

[0597] Production wells 104 may be used to remove formation fluid fromthe formation. Formation fluid produced from production wells 104 may betransported through collection piping 106 to treatment facilities 108.Formation fluids may also be produced from heat sources 100. Forexample, fluid may be produced from heat sources 100 to control pressurewithin the formation adjacent to the heat sources. Fluid produced fromheat sources 100 may be transported through tubing or piping tocollection piping 106 or the produced fluid may be transported throughtubing or piping directly to treatment facilities 108. Treatmentfacilities 108 may include separation units, reaction units, upgradingunits, fuel cells, turbines, storage vessels, and other systems andunits for processing produced formation fluids.

[0598] An in situ conversion system for treating hydrocarbons mayinclude dewatering wells 110 (wells shown with reference number 110 may,in some embodiments, be capture, barrier, and/or isolation wells).Dewatering wells 110 or vacuum wells may remove liquid water and/orinhibit liquid water from entering a portion of a relatively permeableformation to be heated, or to a formation being heated. A plurality ofwater wells may surround all or a portion of a formation to be heated.In the embodiment depicted in FIG. 2, dewatering wells 110 are shownextending only along one side of heat sources 100, but dewatering wellstypically encircle all heat sources 100 used, or to be used, to heat theformation.

[0599] Dewatering wells 110 may be placed in one or more ringssurrounding selected portions of the formation. New dewatering wells mayneed to be installed as an area being treated by the in situ conversionprocess expands. An outermost row of dewatering wells may inhibit asignificant amount of water from flowing into the portion of formationthat is heated or to be heated. Water produced from the outermost row ofdewatering wells should be substantially clean, and may require littleor no treatment before being released. An innermost row of dewateringwells may inhibit water that bypasses the outermost row from flowinginto the portion of formation that is heated or to be heated. Theinnermost row of dewatering wells may also inhibit outward migration ofvapor from a heated portion of the formation into surrounding portionsof the formation. Water produced by the innermost row of dewateringwells may include some hydrocarbons. The water may need to be treatedbefore being released. Alternately, water with hydrocarbons may bestored and used to produce synthesis gas from a portion of the formationduring a synthesis gas phase of the in situ conversion process. Thedewatering wells may reduce heat loss to surrounding portions of theformation, may increase production of vapors from the heated portion,and/or may inhibit contamination of a water table proximate the heatedportion of the formation.

[0600] In some embodiments, pressure differences between successive rowsof dewatering wells may be minimized (e.g., maintained relatively low ornear zero) to create a “no or low flow” boundary between rows.

[0601] In some in situ conversion process embodiments, a fluid may beinjected in the innermost row of wells. The injected fluid may maintaina sufficient pressure around a pyrolysis zone to inhibit migration offluid from the pyrolysis zone through the formation. The fluid may actas an isolation barrier between the outermost wells and the pyrolysisfluids. The fluid may improve the efficiency of the dewatering wells.

[0602] In certain embodiments, wells initially used for one purpose maybe later used for one or more other purposes, thereby lowering projectcosts and/or decreasing the time required to perform certain tasks. Forinstance, production wells (and in some circumstances heater wells) mayinitially be used as dewatering wells (e.g., before heating is begunand/or when heating is initially started). In addition, in somecircumstances dewatering wells can later be used as production wells(and in some circumstances heater wells). As such, the dewatering wellsmay be placed and/or designed so that such wells can be later used asproduction wells and/or heater wells. The heater wells may be placedand/or designed so that such wells can be later used as production wellsand/or dewatering wells. The production wells may be placed and/ordesigned so that such wells can be later used as dewatering wells and/orheater wells. Similarly, injection wells may be wells that initiallywere used for other purposes (e.g., heating, production, dewatering,monitoring, etc.), and injection wells may later be used for otherpurposes. Similarly, monitoring wells may be wells that initially wereused for other purposes (e.g., heating, production, dewatering,injection, etc.), and monitoring wells may later be used for otherpurposes.

[0603] Hydrocarbons to be subjected to in situ conversion may be locatedunder a large area. The in situ conversion system may be used to treatsmall portions of the formation, and other sections of the formation maybe treated as time progresses. In an embodiment of a system for treatinga formation, a field layout for 24 years of development may be dividedinto 24 individual plots that represent individual drilling years. Eachplot may include 120 “tiles” (repeating matrix patterns) wherein eachplot is made of 6 rows by 20 columns of tiles. Each tile may include 1production well and 12 or 18 heater wells. The heater wells may beplaced in an equilateral triangle pattern with a well spacing of about12 m. Production wells may be located in centers of equilateraltriangles of heater wells, or the production wells may be locatedapproximately at a midpoint between two adjacent heater wells.

[0604] In certain embodiments, heat sources will be placed within aheater well formed within a relatively permeable formation. The heaterwell may include an opening through an overburden of the formation. Theheater may extend into or through at least one hydrocarbon containingsection (or hydrocarbon containing layer) of the formation. As shown inFIG. 3, an embodiment of heater well 224 may include an opening inhydrocarbon layer 222 that has a helical or spiral shape. A spiralheater well may increase contact with the formation as opposed to avertically positioned heater. A spiral heater well may provide expansionroom that inhibits buckling or other modes of failure when the heaterwell is heated or cooled. In some embodiments, heater wells may includesubstantially straight sections through overburden 220. Use of astraight section of heater well through the overburden may decrease heatloss to the overburden and reduce the cost of the heater well.

[0605] As shown in FIG. 4, a heat source embodiment may be placed intoheater well 224. Heater well 224 may be substantially “U” shaped. Thelegs of the “U” may be wider or more narrow depending on the particularheater well and formation characteristics. First portion 226 and thirdportion 228 of heater well 224 may be arranged substantiallyperpendicular to an upper surface of hydrocarbon layer 222 in someembodiments. In addition, the first and the third portion of the heaterwell may extend substantially vertically through overburden 220. Secondportion 230 of heater well 224 may be substantially parallel to theupper surface of the hydrocarbon layer.

[0606] Multiple heat sources (e.g., 2, 3, 4, 5, 10 heat sources or more)may extend from a heater well in some situations. As shown in FIG. 5,heat sources 232, 234, and 236 extend through overburden 220 intohydrocarbon layer 222 from heater well 224. Multiple wells extendingfrom a single wellbore may be used when surface considerations (e.g.,aesthetics, surface land use concerns, and/or unfavorable soilconditions near the surface) make it desirable to concentrate wellplatforms in a small area. For example, in areas where the soil isfrozen and/or marshy, it may be more cost-effective to have a minimalnumber of well platforms located at selected sites.

[0607] In certain embodiments, a first portion of a heater well mayextend from the ground surface, through an overburden, and into arelatively permeable formation. A second portion of the heater well mayinclude one or more heater wells in the relatively permeable formation.The one or more heater wells may be disposed within the relativelypermeable formation at various angles. In some embodiments, at least oneof the heater wells may be disposed substantially parallel to a boundaryof the relatively permeable formation. In alternate embodiments, atleast one of the heater wells may be substantially perpendicular to therelatively permeable formation. In addition, one of the one or moreheater wells may be positioned at an angle between perpendicular andparallel to a layer in the formation.

[0608]FIG. 6 illustrates a schematic of view of multilateral or sidetracked lateral heaters branched from a single well in a relativelypermeable formation. In relatively thin and deep layers found in arelatively permeable formation (e.g., in a tar sands formation), it maybe advantageous to place more than one heater substantially horizontallywithin the relatively thin layer of hydrocarbons. Heat provided to athin layer with a low thermal conductivity from a horizontal wellboremay be more effectively trapped within the thin layer and reduce heatlosses from the layer. Substantially vertical opening 6108 may be placedin hydrocarbon layer 6100. Substantially vertical opening 6108 may be anelongated portion of an opening formed in hydrocarbon layer 6100.Hydrocarbon layer 6100 may be below overburden 540.

[0609] One or more substantially horizontal openings 6102 may also beplaced in hydrocarbon layer 6100. Horizontal openings 6102 may, in someembodiments, contain perforated liners. The horizontal openings 6102 maybe coupled to vertical opening 6108. Horizontal openings 6102 may beelongated portions that diverge from the elongated portion of verticalopening 6108. Horizontal openings 6102 may be formed in hydrocarbonlayer 6100 after vertical opening 6108 has been formed. In certainembodiments, openings 6102 may be angled upwards to facilitate flow offormation fluids towards the production conduit.

[0610] Each horizontal opening 6102 may lie above or below an adjacenthorizontal opening. In an embodiment, six horizontal openings 6102 maybe formed in hydrocarbon layer 6100. Three horizontal openings 6102 mayface 180°, or in a substantially opposite direction, from threeadditional horizontal openings 6102. Two horizontal openings facingsubstantially opposite directions may lie in a substantially identicalvertical plane within the formation. Any number of horizontal openings6102 may be coupled to a single vertical opening 6108, depending on, butnot limited to, a thickness of hydrocarbon layer 6100, a type offormation, a desired heating rate in the formation, and a desiredproduction rate.

[0611] Production conduit 6106 may be placed substantially verticallywithin vertical opening 6108. Production conduit 6106 may besubstantially centered within vertical opening 6108. Pump 6107 may becoupled to production conduit 6106. Such pump may be used, in someembodiments, to pump formation fluids from the bottom of the well. Pump6107 may be a rod pump, progressing cavity pump (PCP), centrifugal pump,jet pump, gas lift pump, submersible pump, rotary pump, etc.

[0612] One or more heaters 6104 may be placed within each horizontalopening 6102. Heaters 6104 may be placed in hydrocarbon layer 6100through vertical opening 6108 and into horizontal opening 6102.

[0613] In some embodiments, heater 6104 may be used to generate heatalong a length of the heater within vertical opening 6108 and horizontalopening 6102. In other embodiments, heater 6104 may be used to generateheat only within horizontal opening 6102. In certain embodiments, heatgenerated by heater 6104 may be varied along its length and/or variedbetween vertical opening 6108 and horizontal opening 6102. For example,less heat may be generated by heater 6104 in vertical opening 6108 andmore heat may be generated by the heater in horizontal opening 6102. Itmay be advantageous to have at least some heating within verticalopening 6108. This may maintain fluids produced from the formation in avapor phase in production conduit 6106 and/or may upgrade the producedfluids within the production well. Having production conduit 6106 andheaters 6104 installed into a formation through a single opening in theformation may reduce costs associated with forming openings in theformation and installing production equipment and heaters within theformation.

[0614]FIG. 7 depicts a schematic view from an elevated position of theembodiment of FIG. 6. One or more vertical openings 6108 may be formedin hydrocarbon layer 6100. Each of vertical openings 6108 may lie alonga single plane in hydrocarbon layer 6100. Horizontal openings 6102 mayextend in a plane substantially perpendicular to the plane of verticalopenings 6108. Additional horizontal openings 6102 may lie in a planebelow the horizontal openings as shown in the schematic depiction ofFIG. 6. A number of vertical openings 6108 and/or a spacing betweenvertical openings 6108 may be determined by, for example, a desiredheating rate or a desired production rate. In some embodiments, spacingbetween vertical openings may be about 4 m to about 30 m. Longer orshorter spacings may be used to meet specific formation needs. A lengthof a horizontal opening 6102 may be up to about 1600 m. However, alength of horizontal openings 6102 may vary depending on, for example, amaximum installation cost, an area of hydrocarbon layer 6100, or amaximum producible heater length.

[0615] In an in situ conversion process embodiment, a formation havingone or more thin hydrocarbon layers may be treated. The hydrocarbonlayer may be, but is not limited to, a relatively thin hydrocarbon layerin a tar sands formation. In some in situ conversion processembodiments, such formations may be treated with heat sources that arepositioned substantially horizontal within and/or adjacent to the thinhydrocarbon layer or thin hydrocarbon layers. A relatively thinhydrocarbon layer may be at a substantial depth below a ground surface.For example, a formation may have an overburden of up to about 650 m indepth. The cost of drilling a large number of substantially verticalwells within a formation to a significant depth may be expensive. It maybe advantageous to place heaters horizontally within these formations toheat large portions of the formation for lengths up to about 1600 m.Using horizontal heaters may reduce the number of vertical wells thatare needed to place a sufficient number of heaters within the formation.

[0616]FIG. 8 illustrates an embodiment of hydrocarbon containing layer200 that may be at a near-horizontal angle with respect to an uppersurface of ground 204. An angle of hydrocarbon containing layer 200,however, may vary. For example, hydrocarbon containing layer 200 may dipor be steeply dipping. Economically viable production of a steeplydipping hydrocarbon containing layer may not be possible using presentlyavailable mining methods.

[0617] A dipping or relatively steeply dipping hydrocarbon containinglayer may be subjected to an in situ conversion process. For example, aset of production wells may be disposed near a highest portion of adipping hydrocarbon layer of a relatively permeable formation.Hydrocarbon portions adjacent to and below the production wells may beheated to pyrolysis temperature. Pyrolysis fluid may be produced fromthe production wells. As production from the top portion declines,deeper portions of the formation may be heated to pyrolysistemperatures. Vapors may be produced from the hydrocarbon containinglayer by transporting vapor through the previously pyrolyzedhydrocarbons. High permeability resulting from pyrolysis and productionof fluid from the upper portion of the formation may allow for vaporphase transport with minimal pressure loss. Vapor phase transport offluids produced in the formation may eliminate a need to have deepproduction wells in addition to the set of production wells. A number ofproduction wells required to process the formation may be reduced.Reducing the number of production wells required for production mayincrease economic viability of an in situ conversion process.

[0618] In steeply dipping formations, directional drilling may be usedto form an opening in the formation for a heater well or productionwell. Directional drilling may include drilling an opening in which theroute/course of the opening may be planned before drilling. Such anopening may usually be drilled with rotary equipment. In directionaldrilling, a route/course of an opening may be controlled by deflectionwedges, etc.

[0619] A wellbore may be formed using a drill equipped with a steerablemotor and an accelerometer. The steerable motor and accelerometer mayallow the wellbore to follow a layer in the relatively permeableformation. A steerable motor may maintain a substantially constantdistance between heater well 202 and a boundary of hydrocarboncontaining layer 200 throughout drilling of the opening.

[0620] In some in situ conversion embodiments, geosteered drilling maybe used to drill a wellbore in a relatively permeable formation.Geosteered drilling may include determining or estimating a distancefrom an edge of hydrocarbon containing layer 200 to the wellbore with asensor. The sensor may monitor variations in characteristics or signalsin the formation. The characteristic or signal variance may allow fordetermination of a desired drill path. The sensor may monitorresistance, acoustic signals, magnetic signals, gamma rays, and/or othersignals within the formation. A drilling apparatus for geosteereddrilling may include a steerable motor. The steerable motor may becontrolled to maintain a predetermined distance from an edge of ahydrocarbon containing layer based on data collected by the sensor.

[0621] In some in situ conversion embodiments, wellbores may be formedin a formation using other techniques. Wellbores may be formed byimpaction techniques and/or by sonic drilling techniques. The methodused to form wellbores may be determined based on a number of factors.The factors may include, but are not limited to, accessibility of thesite, depth of the wellbore, properties of the overburden, andproperties of the hydrocarbon containing layer or layers.

[0622]FIG. 9 illustrates an embodiment of a plurality of heater wells210 formed in hydrocarbon layer 212. Hydrocarbon layer 212 may be asteeply dipping layer. One or more of heater wells 210 may be formed inthe formation such that two or more of the heater wells aresubstantially parallel to each other, and/or such that at least oneheater well is substantially parallel to a boundary of hydrocarbon layer212. For example, one or more of heater wells 210 may be formed inhydrocarbon layer 212 by a magnetic steering method. An example of amagnetic steering method is illustrated in U.S. Pat. No. 5,676,212 toKuckes, which is incorporated by reference as if fully set forth herein.Magnetic steering may include drilling heater well 210 parallel to anadjacent heater well. The adjacent well may have been previouslydrilled. In addition, magnetic steering may include directing thedrilling by sensing and/or determining a magnetic field produced in anadjacent heater well. For example, the magnetic field may be produced inthe adjacent heater well by flowing a current through an insulatedcurrent-carrying wireline disposed in the adjacent heater well.

[0623] Magnetic steering may include directing the drilling by sensingand/or determining a magnetic field produced in an adjacent well. Forexample, the magnetic field may be produced in the adjacent well byflowing a current through an insulated current-carrying wirelinedisposed in the adjacent well. In some embodiments, magnetostaticsteering may be used to form openings adjacent to a first opening. U.S.Pat. No. 5,541,517, issued to Hartmann et al., which is incorporated byreference as if fully set forth herein, describes a method for drillinga wellbore relative to a second wellbore that has magnetized casingportions.

[0624] When drilling a wellbore (opening), a magnet or magnets may beinserted into a first opening to provide a magnetic field used to guidea drilling mechanism that forms an adjacent opening or adjacentopenings. The magnetic field may be detected by a 3-axis fluxgatemagnetometer in the opening being drilled. A control system may useinformation detected by the magnetometer to determine and implementoperation parameters needed to form an opening that is a selecteddistance away (e.g., parallel) from the first opening (within desiredtolerances). Some types of wells may require or need close tolerances.For example, freeze wells may need to be positioned parallel to eachother with small or no variance in parallel alignment to allow forformation of a continuous frozen barrier around a treatment area. Also,vertical and/or horizontally positioned heater wells and/or productionwells may need to be positioned parallel to each other with small or novariance in parallel alignment to allow for substantially uniformheating and/or production from a treatment area in a formation.

[0625]FIG. 10 depicts a schematic representation of an embodiment of amagnetostatic drilling operation to form an opening that is a selecteddistance away from (e.g., substantially parallel to) a drilled opening.Opening 514 may be formed in formation 6100. Opening 514 may be a casedopening or an open hole opening. Magnetic string 9678 may be insertedinto opening 514. Magnetic string 9678 may be unwound from a reel intoopening 514. In an embodiment, magnetic string includes several segments9680 of magnets within casing 6152.

[0626] In some embodiments, casing 6152 may be a conduit made of amaterial that is not significantly influenced by a magnetic field (e.g.,non-magnetic alloy such as non-magnetic stainless steel (e.g., 304, 310,316 stainless steel), reinforced polymer pipe, or brass tubing). Thecasing may be a conduit of a conductor-in-conduit heater, or it may beperforated liner or casing. If the casing is not significantlyinfluenced by a magnetic field, then the magnetic flux will not beshielded. In other embodiments, the casing may be made of a materialthat is influenced by a magnetic field (e.g., carbon steel). The use ofa material that is influenced by a magnetic field may weaken thestrength of the magnetic field to be detected by drilling apparatus 9684in adjacent opening 9685.

[0627] Magnets may be inserted in conduits 9681 in segments 9680.Conduits 9681 may be threaded or seamless coiled tubing (e.g., tubinghaving an inside diameter of about 5 cm). Members 9682 (e.g., pins) maybe placed between segments 9680 to inhibit movement of segments 9680relative to conduit 9681. Magnets from adjoining segments of conduit maybe close to each other or touch each other as, for example, threadedsections of conduit are tightened together. A segment may be made ofseveral north-south aligned magnets. Alignment of the magnets allowseach segment to effectively be a long magnet. In an embodiment, asegment may include one magnet. Magnets may be Alnico magnets or othertypes of magnets having significant magnetic strength. Two adjacentsegments may be oriented to have opposite polarities so that thesegments repel each other.

[0628] The magnetic string may include 2 or more magnetic segments.Segments may range in length from about 1.5 m to about 15 m. Magneticsegments may be formed from several magnets. Magnets used to formsegments may have diameters greater than about 1 cm (about 4.5 cm). Themagnets may be oriented so that the magnets are attracted to each other.For example, a segment may be made of 40 magnets each having a length ofabout 0.15 m.

[0629]FIG. 11 depicts a schematic of a portion of magnetic string.Segments 9680 may be positioned such that adjacent segments 9680 haveopposing polarities. In some embodiments, force may be applied tominimize distance 9692 between segments 9680. Additional segments may beadded to increase a length of magnetic string 9678. Magnetic strings maybe coiled after assembling. Installation of the magnetic string mayinclude uncoiling the magnetic string.

[0630] For example, first segment 9697 may be positioned north-south inthe conduit and second segment 9698 may be positioned south-north suchthat the south poles of segments 9697, 9698 are proximate each other.Third segment 9696 may positioned in the conduit may be positioned in anorth-south orientation such that the north poles of segments 9697, 9696are proximate each other. Magnet strings may include multiplesouth-south and north-north interfaces. As shown in FIG. 11, thisconfiguration may induce a series of magnetic fields 9694.

[0631] Alternating the polarity of the segments within a magnetic stringmay provide several magnetic field differentials that allow forreduction in the amount of deviation that is a selected distance betweenthe openings. Increasing a length of the segments within the magneticstring may increase the radial distance at which the magnetometer maydetect a magnetic field. In some embodiments, the length of segmentswithin the magnetic string may be varied. For example, more magnets maybe used in the segment proximate the earth's surface than in segmentspositioned in the formation.

[0632] In an embodiment, when the separation distance between twowellbores increases, then the segment length of the magnetic strings mayalso be increased, and vice versa. With shorter segment lengths, whilethe overall strength of the magnetic field is decreased, variations inthe magnetic field occur more frequently, thus providing more guidanceto the drilling operation. For example, segments having a length ofabout 6 m may induce a magnetic field sufficient to allow drilling ofadjacent openings at distances of less than about 16 m. Thisconfiguration may allow a desired tolerance between the adjacentopenings to be achieved.

[0633] In alternate embodiments, the strength of the magnets used mayaffect a strength of the magnetic field induced. For example, when usingmagnets having a lower strength than those in the example above, asegment length of about 6 m may induce a magnetic field sufficient todrill adjacent openings at distances of less than about 6 m. In someembodiments, a segment length of about 6 m may induce a magnetic fieldsufficient to drill adjacent openings at distances of less than about 10m A length of the magnetic string may be based on an economic balancebetween cost of the string and the cost of having to reposition thestring during drilling. A string length may range from about 30 m toabout 500 m. In an embodiment, a magnetic string may have a length ofabout 150 m. Thus, in some embodiments, the magnetic string may need tobe repositioned if the openings being drilled are longer than the lengthof the string.

[0634] When multiple wellbores are to be drilled, it is possible toinitially drill a center wellbore, and then use magnetic strings in thatcenter wellbore to guide the drilling of the other wellboressubstantially surrounding the center wellbore. In this manner cumulativeerrors may be limited since, for example, movement of the magneticstring may be minimized. In addition, only the center well in thisembodiment will include a more expensive nonmagnetic liner.

[0635] In some embodiments, heated portion 310 may extend radially fromheat source 300, as shown in FIG. 12. For example, a width of heatedportion 310, in a direction extending radially from heat source 300, maybe about 0 m to about 10 m. A width of heated portion 310 may vary,however, depending upon, for example, heat provided by heat source 300and the characteristics of the formation. Heat provided by heat source300 will typically transfer through the heated portion to create atemperature gradient within the heated portion. For example, atemperature proximate the heater well will generally be higher than atemperature proximate an outer lateral boundary of the heated portion. Atemperature gradient within the heated portion may vary within theheated portion depending on various factors (e.g., thermal conductivityof the formation, density, and porosity).

[0636] As heat transfers through heated portion 310 of the relativelypermeable formation, a temperature within at least a section of theheated portion may be within a pyrolysis temperature range. As the heattransfers away from the heat source, a front at which pyrolysis occurswill in many instances travel outward from the heat source. For example,heat from the heat source may be allowed to transfer into a selectedsection of the heated portion such that heat from the heat sourcepyrolyzes at least some of the hydrocarbons within the selected section.Pyrolysis may occur within selected section 315 of the heated portion,and pyrolyzation fluids will be generated in the selected section.

[0637] Selected section 315 may have a width radially extending from theinner lateral boundary of the selected section. For a single heat sourceas depicted in FIG. 12, width of the selected section may be dependenton a number of factors. The factors may include, but are not limited to,time that heat source 300 is supplying energy to the formation, thermalconductivity properties of the formation, extent of pyrolyzation ofhydrocarbons in the formation. A width of selected section 315 mayexpand for a significant time after initialization of heat source 300. Awidth of selected section 315 may initially be zero and may expand to 10m or more after initialization of heat source 300. An inner boundary ofselected section 315 may be radially spaced from the heat source. Theinner boundary may define a volume of spent hydrocarbons 317. Spenthydrocarbons 317 may include a volume of hydrocarbon material that istransformed to coke due to the proximity and heat of heat source 300.Coking may occur by pyrolysis reactions that occur due to a rapidincrease in temperature in a short time period. Applying heat to aformation at a controlled rate may allow for avoidance of significantcoking, however, some coking may occur in the vicinity of heat sources.Spent hydrocarbons 317 may also include a volume of material that hasbeen subjected to pyrolysis and the removal of pyrolysis fluids. Thevolume of material that has been subjected to pyrolysis and the removalof pyrolysis fluids may produce insignificant amounts or no additionalpyrolysis fluids with increases in temperature. The inner lateralboundary may advance radially outwards as time progresses duringoperation of an in situ conversion process.

[0638] In some embodiments, a plurality of heated portions may existwithin a unit of heat sources. A unit of heat sources refers to aminimal number of heat sources that form a template that is repeated tocreate a pattern of heat sources within the formation. The heat sourcesmay be located within the formation such that superposition(overlapping) of heat produced from the heat sources occurs. Forexample, as illustrated in FIG. 13, transfer of heat from two or moreheat sources 330 results in superposition of heat to region 332 betweenthe heat sources 330. Superposition of heat may occur between two,three, four, five, six, or more heat sources. Region 332 is an area inwhich temperature is influenced by various heat sources. Superpositionof heat may provide the ability to efficiently raise the temperature oflarge volumes of a formation to pyrolysis temperatures. The size ofregion 332 may be significantly affected by the spacing between heatsources.

[0639] Superposition of heat may increase a temperature in at least aportion of the formation to a temperature sufficient for pyrolysis ofhydrocarbons within the portion. Superposition of heat to region 332 mayincrease the quantity of hydrocarbons in a formation that are subjectedto pyrolysis. Selected sections of a formation that are subjected topyrolysis may include regions 334 brought into a pyrolysis temperaturerange by heat transfer from substantially only one heat source. Selectedsections of a formation that are subjected to pyrolysis may also includeregions 332 brought into a pyrolysis temperature range by superpositionof heat from multiple heat sources.

[0640] A pattern of heat sources will often include many units of heatsources. There will typically be many heated portions, as well as manyselected sections within the pattern of heat sources. Superposition ofheat within a pattern of heat sources may decrease the time necessary toreach pyrolysis temperatures within the multitude of heated portions.Superposition of heat may allow for a relatively large spacing betweenadjacent heat sources. In some embodiments, a large spacing may providefor a relatively slow heating rate of hydrocarbon material. The slowheating rate may allow for pyrolysis of hydrocarbon material withminimal coking or no coking within the formation away from areas in thevicinity of the heat sources. Heating from heat sources allows theselected section to reach pyrolysis temperatures so that allhydrocarbons within the selected section may be subject to pyrolysisreactions. In some in situ conversion embodiments, a majority ofpyrolysis fluids are produced when the selected section is within arange from about 0 m to about 25 m from a heat source.

[0641] In an in situ conversion process embodiment, a heating rate maybe controlled to minimize costs associated with heating a selectedsection. The costs may include, for example, input energy costs andequipment costs. In certain embodiments, a cost associated with heatinga selected section may be minimized by reducing a heating rate when thecost associated with heating is relatively high and increasing theheating rate when the cost associated with heating is relatively low.For example, a heating rate of about 330 watts/m may be used when theassociated cost is relatively high, and a heating rate of about 1640watts/m may be used when the associated cost is relatively low. The costassociated with heating may be relatively high at peak times of energyuse, such as during the daytime. For example, energy use may be high inwarm climates during the daytime in the summer due to energy use for airconditioning. Low times of energy use may be, for example, at night orduring weekends, when energy demand tends to be lower. In an embodiment,the heating rate may be varied from a higher heating rate during lowenergy usage times, such as during the night, to a lower heating rateduring high energy usage times, such as during the day.

[0642] As shown in FIG. 2, in addition to heat sources 100, one or moreproduction wells 104 will typically be placed within the portion of therelatively permeable formation. Formation fluids may be produced throughproduction well 104. In some embodiments, production well 104 mayinclude a heat source. The heat source may heat the portions of theformation at or near the production well and allow for vapor phaseremoval of formation fluids. The need for high temperature pumping ofliquids from the production well may be reduced or eliminated. Avoidingor limiting high temperature pumping of liquids may significantlydecrease production costs. Providing heating at or through theproduction well may: (1) inhibit condensation and/or refluxing ofproduction fluid when such production fluid is moving in the productionwell proximate the overburden, (2) increase heat input into theformation, and/or (3) increase formation permeability at or proximatethe production well. In some in situ conversion process embodiments, anamount of heat supplied to production wells is significantly less thanan amount of heat applied to heat sources that heat the formation.

[0643] Because permeability and/or porosity increases in the heatedformation, produced vapors may flow considerable distances through theformation with relatively little pressure differential. Increases inpermeability may result from a reduction of mass of the heated portiondue to vaporization of water, removal of hydrocarbons, and/or creationof fractures. Fluids may flow more easily through the heated portion. Insome embodiments, production wells may be provided in upper portions ofhydrocarbon layers. As shown in FIG. 8, production wells 206 may extendinto a relatively permeable formation near the top of heated portion208. Extending production wells significantly into the depth of theheated hydrocarbon layer may be unnecessary.

[0644] Fluid generated within a relatively permeable formation may movea considerable distance through the relatively permeable formation as avapor. The considerable distance may be over 1000 m depending on variousfactors (e.g., permeability of the formation, properties of the fluid,temperature of the formation, and pressure gradient allowing movement ofthe fluid). Due to increased permeability in formations subjected to insitu conversion and formation fluid removal, production wells may onlyneed to be provided in every other unit of heat sources or every third,fourth, fifth, or sixth units of heat sources.

[0645] Embodiments of a production well may include valves that alter,maintain, and/or control a pressure of at least a portion of theformation. Production wells may be cased wells. Production wells mayhave production screens or perforated casings adjacent to productionzones. In addition, the production wells may be surrounded by sand,gravel or other packing materials adjacent to production zones.Production wells 104 may be coupled to treatment facilities 108, asshown in FIG. 2.

[0646] During an in situ process, production wells may be operated suchthat the production wells are at a lower pressure than other portions ofthe formation. In some embodiments, a vacuum may be drawn at theproduction wells. Maintaining the production wells at lower pressuresmay inhibit fluids in the formation from migrating outside of the insitu treatment area.

[0647]FIG. 14 illustrates an embodiment of production well 6108 placedin hydrocarbon layer 6100. Production well 6108 may be used to produceformation fluids from hydrocarbon layer 6100. Hydrocarbon layer 6100 maybe treated using an in situ conversion process. Production conduit 6106may be placed within production well 6108. In an embodiment, productionconduit 6106 is a hollow sucker rod placed in production well 6108.Production well 6108 may have a casing, or lining, placed along thelength of the production well. The casing may have openings, orperforations, to allow formation fluids to enter production well 6108.Formation fluids may include vapors and/or liquids. Production conduit6106 and production well 6108 may include non-corrosive materials suchas steel.

[0648] In certain embodiments, production conduit 6106 may include heatsource 6105. Heat source 6105 may be a heater placed inside or outsideproduction conduit 6106 or formed as part of the production conduit.Heat source 6105 may be a heater such as an insulated conductor heater,a conductor-in-conduit heater, or a skin-effect heater. A skin-effectheater is an electric heater that uses eddy current heating to induceresistive losses in production conduit 6106 to heat the productionconduit. An example of a skin-effect heater is obtainable from DagangOil Products (China).

[0649] Heating of production conduit 6106 may inhibit condensationand/or refluxing in the production conduit or within production well6108. In certain embodiments, heating of production conduit 6106 mayinhibit plugging of pump 6107 by liquids (e.g., heavy hydrocarbons). Forexample, heat source 6105 may heat production conduit 6106 to about 35°C. to maintain the mobility of liquids in the production conduit toinhibit plugging of pump 6107 or the production conduit. In certainembodiments (e.g., for formations greater than about 100 m in depth),heat source 6105 may heat production conduit 6106 and/or production well6108 to temperatures of about 200° C. to about 250° C. to maintainproduced fluids substantially in a vapor phase by inhibitingcondensation and/or reflux of fluids in the production well.

[0650] Pump 6107 may be coupled to production conduit 6106. Pump 6107may be used to pump formation fluids from hydrocarbon layer 6100 intoproduction conduit 6106. Pump 6107 may be any pump used to pump fluids,such as a rod pump, PCP, jet pump, gas lift pump, centrifugal pump,rotary pump, or submersible pump. Pump 6107 may be used to pump fluidsthrough production conduit 6106 to a surface of the formation aboveoverburden 540.

[0651] In certain embodiments, pump 6107 can be used to pump formationfluids that may be liquids. Liquids may be produced from hydrocarbonlayer 6100 prior to production well 6108 being heated to a temperaturesufficient to vaporize liquids within the production well. In someembodiments, liquids produced from the formation tend to include water.Removing liquids from the formation before heating the formation, orduring early times of heating before pyrolysis occurs, tends to reducethe amount of heat input that is needed to produce hydrocarbons from theformation.

[0652] In an embodiment, formation fluids that are liquids may beproduced through production conduit 6106 using pump 6107. Formationfluids that are vapors may be simultaneously produced through an annulusof production well 6108 outside of production conduit 6106.

[0653] Insulation may be placed on a wall of production well 6108 in asection of the production well within overburden 540. The insulation maybe cement or any other suitable low heat transfer material. Insulatingthe overburden section of production well 6108 may inhibit transfer ofheat from fluids being produced from the formation into the overburden.

[0654] In an in situ conversion process embodiment, a mixture may beproduced from a relatively permeable formation. The mixture may beproduced through a heater well disposed in the formation. Producing themixture through the heater well may increase a production rate of themixture as compared to a production rate of a mixture produced through anon-heater well. A non-heater well may include a production well. Insome embodiments, a production well may be heated to increase aproduction rate.

[0655] A heated production well may inhibit condensation of highercarbon numbers (C₅ or above) in the production well. A heated productionwell may inhibit problems associated with producing a hot, multi-phasefluid from a formation.

[0656] A heated production well may have an improved production rate ascompared to a non-heated production well. Heat applied to the formationadjacent to the production well from the production well may increaseformation permeability adjacent to the production well by, for example,vaporizing and removing liquid phase fluid adjacent to the productionwell. A heater in a lower portion of a production well may be turned offwhen superposition of heat from heat sources heats the formationsufficiently to counteract benefits provided by heating from within theproduction well. In some embodiments, a heater in an upper portion of aproduction well may remain on after a heater in a lower portion of thewell is deactivated. The heater in the upper portion of the well mayinhibit condensation and reflux of formation fluid.

[0657] In some embodiments, heated production wells may improve productquality by causing production through a hot zone in the formationadjacent to the heated production well. A final phase of thermalcracking may exist in the hot zone adjacent to the production well.Producing through a hot zone adjacent to a heated production well mayallow for an increased olefin content in non-condensable hydrocarbonsand/or condensable hydrocarbons in the formation fluids. The hot zonemay produce formation fluids with a greater percentage ofnon-condensable hydrocarbons due to thermal cracking in the hot zone.The extent of thermal cracking may depend on a temperature of the hotzone and/or on a residence time in the hot zone. A heater can bedeliberately run hotter to promote the further in situ upgrading ofhydrocarbons. This may be an advantage in the case of heavy hydrocarbons(e.g., bitumen or tar) in relatively permeable formations, in which someheavy hydrocarbons tend to flow into the production well beforesufficient upgrading has occurred.

[0658] In an embodiment, heating in or proximate a production well maybe controlled such that a desired mixture is produced through theproduction well. The desired mixture may have a selected yield ofnon-condensable hydrocarbons. For example, the selected yield ofnon-condensable hydrocarbons may be about 75 weight % non-condensablehydrocarbons or, in some embodiments, about 50 weight % to about 100weight %. In other embodiments, the desired mixture may have a selectedyield of condensable hydrocarbons. The selected yield of condensablehydrocarbons may be about 75 weight % condensable hydrocarbons or, insome embodiments, about 50 weight % to about 95 weight %.

[0659] A temperature and a pressure may be controlled within theformation to inhibit the production of carbon dioxide and increaseproduction of carbon monoxide and molecular hydrogen during synthesisgas production. In an embodiment, the mixture is produced through aproduction well (or heater well), which may be heated to inhibit theproduction of carbon dioxide. In some embodiments, a mixture producedfrom a first portion of the formation may be recycled into a secondportion of the formation to inhibit the production of carbon dioxide.The mixture produced from the first portion may be at a lowertemperature than the mixture produced from the second portion of theformation.

[0660] A desired volume ratio of molecular hydrogen to carbon monoxidein synthesis gas may be produced from the formation. The desired volumeratio may be about 2.0:1. In an embodiment, the volume ratio may bemaintained between about 1.8:1 and 2.2:1 for synthesis gas.

[0661]FIG. 15 illustrates a pattern of heat sources 400 and productionwells 402 that may be used to treat a relatively permeable formation.Heat sources 400 may be arranged in a unit of heat sources such astriangular pattern 401. Heat sources 400, however, may be arranged in avariety of patterns including, but not limited to, squares, hexagons,and other polygons. The pattern may include a regular polygon to promoteuniform heating of the formation in which the heat sources are placed.The pattern may also be a line drive pattern. A line drive patterngenerally includes a first linear array of heater wells, a second lineararray of heater wells, and a production well or a linear array ofproduction wells between the first and second linear array of heaterwells.

[0662] A distance from a node of a polygon to a centroid of the polygonis smallest for a 3-sided polygon and increases with increasing numberof sides of the polygon. The distance from a node to the centroid for anequilateral triangle is (length/2)/(square root(3)/2) or 0.5774 timesthe length. For a square, the distance from a node to the centroid is(length/2)/(square root(2)/2) or 0.7071 times the length. For a hexagon,the distance from a node to the centroid is (length/2)/(1/2) or thelength. The difference in distance between a heat source and a midpointto a second heat source (length/2) and the distance from a heat sourceto the centroid for an equilateral pattern (0.5774 times the length) issignificantly less for the equilateral triangle pattern than for anyhigher order polygon pattern. The small difference means thatsuperposition of heat may develop more rapidly and that the formationmay rise to a more uniform temperature between heat sources using anequilateral triangle pattern rather than a higher order polygon pattern.

[0663] Triangular patterns tend to provide more uniform heating to aportion of the formation in comparison to other patterns such as squaresand/or hexagons. Triangular patterns tend to provide faster heating to apredetermined temperature in comparison to other patterns such assquares or hexagons. The use of triangular patterns may result insmaller volumes of a formation being overheated. A plurality of units ofheat sources such as triangular pattern 401 may be arrangedsubstantially adjacent to each other to form a repetitive pattern ofunits over an area of the formation. For example, triangular patterns401 may be arranged substantially adjacent to each other in a repetitivepattern of units by inverting an orientation of adjacent triangles 401.Other patterns of heat sources 400 may also be arranged such thatsmaller patterns may be disposed adjacent to each other to form largerpatterns.

[0664] Production wells may be disposed in the formation in a repetitivepattern of units. In certain embodiments, production well 402 may bedisposed proximate a center of every third triangle 401 arranged in thepattern. Production well 402, however, may be disposed in every triangle401 or within just a few triangles. In some embodiments, a productionwell may be placed within every 13, 20, or 30 heater well triangles. Forexample, a ratio of heat sources in the repetitive pattern of units toproduction wells in the repetitive pattern of units may be more thanapproximately 5 (e.g., more than 6, 7, 8, or 9). In some well patternembodiments, three or more production wells may be located within anarea defined by a repetitive pattern of units. For example, as shown inFIG. 15, production wells 410 may be located within an area defined byrepetitive pattern of units 412. Production wells 410 may be located inthe formation in a unit of production wells. The location of productionwells 402, 410 within a pattern of heat sources 400 may be determinedby, for example, a desired heating rate of the relatively permeableformation, a heating rate of the heat sources, the type of heat sourcesused, the type of relatively permeable formation (and its thickness),the composition of the relatively permeable formation, permeability ofthe formation, the desired composition to be produced from theformation, and/or a desired production rate.

[0665] One or more injection wells may be disposed within a repetitivepattern of units. For example, as shown in FIG. 15, injection wells 414may be located within an area defined by repetitive pattern of units416. Injection wells 414 may also be located in the formation in a unitof injection wells. For example, the unit of injection wells may be atriangular pattern. Injection wells 414, however, may be disposed in anyother pattern. In certain embodiments, one or more production wells andone or more injection wells may be disposed in a repetitive pattern ofunits. For example, as shown in FIG. 15, production wells 418 andinjection wells 420 may be located within an area defined by repetitivepattern of units 422. Production wells 418 may be located in theformation in a unit of production wells, which may be arranged in afirst triangular pattern. In addition, injection wells 420 may belocated within the formation in a unit of production wells, which arearranged in a second triangular pattern. The first triangular patternmay be different than the second triangular pattern. For example, areasdefined by the first and second triangular patterns may be different.

[0666] One or more monitoring wells may be disposed within a repetitivepattern of units. Monitoring wells may include one or more devices thatmeasure temperature, pressure, and/or fluid properties. In someembodiments, logging tools may be placed in monitoring well wellbores tomeasure properties within a formation. The logging tools may be moved toother monitoring well wellbores as needed. The monitoring well wellboresmay be cased or uncased wellbores. As shown in FIG. 15, monitoring wells424 may be located within an area defined by repetitive pattern of units426. Monitoring wells 424 may be located in the formation in a unit ofmonitoring wells, which may be arranged in a triangular pattern.Monitoring wells 424, however, may be disposed in any of the otherpatterns within repetitive pattern of units 426.

[0667] It is to be understood that a geometrical pattern of heat sources400 and production wells 402 is described herein by example. A patternof heat sources and production wells will in many instances varydepending on, for example, the type of relatively permeable formation tobe treated. For example, for relatively thin layers, heater wells may bealigned along one or more layers along strike or along dip. Forrelatively thick layers, heat sources may be at an angle to one or morelayers (e.g., orthogonally or diagonally).

[0668] A triangular pattern of heat sources may treat a hydrocarbonlayer having a thickness of about 10 m or more. For a thin hydrocarbonlayer (e.g., about 10 m thick or less) a line and/or staggered linepattern of heat sources may treat the hydrocarbon layer.

[0669] For certain thin layers, heating wells may be placed close to anedge of the layer (e.g., in a staggered line instead of a line placed inthe center of the layer) to increase the amount of hydrocarbons producedper unit of energy input. A portion of input heating energy may heatnon-hydrocarbon portions of the formation, but the staggered pattern mayallow superposition of heat to heat a majority of the hydrocarbon layersto pyrolysis temperatures. If the thin formation is heated by placingone or more heater wells in the layer along a center of the thickness, asignificant portion of the hydrocarbon layers may not be heated topyrolysis temperatures. In some embodiments, placing heater wells closerto an edge of the layer may increase the volume of layer undergoingpyrolysis per unit of energy input.

[0670] Exact placement of heater wells, production wells, etc. willdepend on variables specific to the formation (e.g., thickness of thelayer or composition of the layer), project economics, etc. In certainembodiments, heater wells may be substantially horizontal whileproduction wells may be vertical, or vice versa. In some embodiments,wells may be aligned along dip or strike or oriented at an angle betweendip and strike.

[0671] The spacing between heat sources may vary depending on a numberof factors. The factors may include, but are not limited to, the type ofa relatively permeable formation, the selected heating rate, and/or theselected average temperature to be obtained within the heated portion.In some well pattern embodiments, the spacing between heat sources maybe within a range of about 5 m to about 25 m. In some well patternembodiments, spacing between heat sources may be within a range of about8 m to about 15 m.

[0672] The spacing between heat sources may influence the composition offluids produced from a relatively permeable formation. In an embodiment,a computer-implemented simulation may be used to determine optimum heatsource spacings within a relatively permeable formation. At least oneproperty of a portion of relatively permeable formation can usually bemeasured. The measured property may include, but is not limited to,hydrogen content, atomic hydrogen to carbon ratio, oxygen content,atomic oxygen to carbon ratio, water content, thickness of therelatively permeable formation, and/or the amount of stratification ofthe relatively permeable formation into separate layers of rock andhydrocarbons.

[0673] In certain embodiments, a computer-implemented simulation mayinclude providing at least one measured property to a computer system.One or more sets of heat source spacings in the formation may also beprovided to the computer system. For example, a spacing between heatsources may be less than about 30 m. Alternatively, a spacing betweenheat sources may be less than about 15 m. The simulation may includedetermining properties of fluids produced from the portion as a functionof time for each set of heat source spacings. The produced fluids mayinclude formation fluids such as pyrolyzation fluids or synthesis gas.The determined properties may include, but are not limited to, APIgravity, carbon number distribution, olefin content, hydrogen content,carbon monoxide content, and/or carbon dioxide content. The determinedset of properties of the produced fluid may be compared to a set ofselected properties of a produced fluid. Sets of properties that matchthe set of selected properties may be determined. Furthermore, heatsource spacings may be matched to heat source spacings associated withdesired properties.

[0674] As shown in FIG. 15, unit cell 404 will often include a number ofheat sources 400 disposed within a formation around each production well402. An area of unit cell 404 may be determined by midlines 406 that maybe equidistant and perpendicular to a line connecting two productionwells 402. Vertices 408 of the unit cell may be at the intersection oftwo midlines 406 between production wells 402. Heat sources 400 may bedisposed in any arrangement within the area of unit cell 404. Forexample, heat sources 400 may be located within the formation such thata distance between each heat source varies by less than approximately10%, 20%, or 30%. In addition, heat sources 400 may be disposed suchthat an approximately equal space exists between each of the heatsources. Other arrangements of heat sources 400 within unit cell 404 maybe used. A ratio of heat sources 400 to production wells 402 may bedetermined by counting the number of heat sources 400 and productionwells 402 within unit cell 404 or over the total field.

[0675]FIG. 16 illustrates an embodiment of unit cell 404. Unit cell 404includes heat sources 400 and production well 402. Unit cell 404 mayhave six full heat sources 400 a and six partial heat sources 400 b.Full heat sources 400 a may be closer to production well 402 thanpartial heat sources 400 b. In addition, an entirety of each of fullheat sources 400 a may be located within unit cell 404. Partial heatsources 400 b may be partially disposed within unit cell 404. Only aportion of heat source 400 b disposed within unit cell 404 may provideheat to a portion of a relatively permeable formation disposed withinunit cell 404. A remaining portion of heat source 400 b disposed outsideof unit cell 404 may provide heat to a remaining portion of therelatively permeable formation outside of unit cell 404. To determine anumber of heat sources within unit cell 404, partial heat source 400 bmay be counted as one-half of full heat source 400 a. In other unit cellembodiments, fractions other than ½ (e.g., 1/3) may more accuratelydescribe the amount of heat applied to a portion from a partial heatsource based on geometrical considerations.

[0676] The total number of heat sources 400 in unit cell 404 may includesix full heat sources 400 a that are each counted as one heat source,and six partial heat sources 400 b that are each counted as one-half ofa heat source. Therefore a ratio of heat sources 400 to production wells402 in unit cell 404 may be determined as 9:1. A ratio of heat sourcesto production wells may be varied, however, depending on, for example,the desired heating rate of the relatively permeable formation, theheating rate of the heat sources, the type of heat source, the type ofrelatively permeable formation, the composition of relatively permeableformation, the desired composition of the produced fluid, and/or thedesired production rate. Providing more heat source wells per unit areawill allow faster heating of the selected portion and thus hasten theonset of production. However, adding more heat sources will generallycost more money in installation and equipment. An appropriate ratio ofheat sources to production wells may include ratios greater than about5:1. In some embodiments, an appropriate ratio of heat sources toproduction wells may be about 10:1, 20:1, 50:1, or greater. If largerratios are used, then project costs tend to decrease since less wellsand equipment are needed.

[0677] A selected section is generally the volume of formation that iswithin a perimeter defined by the location of the outermost heat sources(assuming that the formation is viewed from above). For example, if fourheat sources were located in a single square pattern with an area ofabout 100 m² (with each source located at a corner of the square), andif the formation had an average thickness of approximately 5 m acrossthis area, then the selected section would be a volume of about 500 m³(i.e., the area multiplied by the average formation thickness across thearea). In many commercial applications, many heat sources (e.g.,hundreds or thousands) may be adjacent to each other to heat a selectedsection, and therefore only the outermost heat sources (i.e., edge heatsources) would define the perimeter of the selected section.

[0678]FIG. 17 illustrates a typical computational system 6250 that issuitable for implementing various embodiments of the system and methodfor in situ processing of a formation. Each computational system 6250typically includes components such as one or more central processingunits (CPU) 6252 with associated memory mediums, represented by floppydisks or compact discs (CDs) 6260. The memory mediums may store programinstructions for computer programs, wherein the program instructions areexecutable by CPU 6252. Computational system 6250 may further includeone or more display devices such as monitor 6254, one or morealphanumeric input devices such as keyboard 6256, and one or moredirectional input devices such as mouse 6258. Computational system 6250is operable to execute the computer programs to implement (e.g.,control, design, simulate, and/or operate) in situ processing offormation systems and methods.

[0679] Computational system 6250 preferably includes one or more memorymediums on which computer programs according to various embodiments maybe stored. The term “memory medium” may include an installation medium,e.g., CD-ROM or floppy disks 6260, a computational system memory such asDRAM, SRAM, EDO DRAM, SDRAM, DDR SDRAM, Rambus RAM, etc., or anon-volatile memory such as a magnetic media (e.g., a hard drive) oroptical storage. The memory medium may include other types of memory aswell, or combinations thereof. In addition, the memory medium may belocated in a first computer that is used to execute the programs.Alternatively, the memory medium may be located in a second computer, orother computers, connected to the first computer (e.g., over a network).In the latter case, the second computer provides the programinstructions to the first computer for execution. Also, computationalsystem 6250 may take various forms, including a personal computer,mainframe computational system, workstation, network appliance, Internetappliance, personal digital assistant (PIDA), television system, orother device. In general, the term “computational system” can be broadlydefined to encompass any device, or system of devices, having aprocessor that executes instructions from a memory medium.

[0680] The memory medium preferably stores a software program orprograms for event-triggered transaction processing. The softwareprogram(s) may be implemented in any of various ways, includingprocedure-based techniques, component-based techniques, and/orobject-oriented techniques, among others. For example, the softwareprogram may be implemented using ActiveX controls, C++ objects,JavaBeans, Microsoft Foundation Classes (MFC), or other technologies ormethodologies, as desired. A CPU, such as host CPU 6252, executing codeand data from the memory medium, includes a system/process for creatingand executing the software program or programs according to the methodsand/or block diagrams described below.

[0681] In one embodiment, the computer programs executable bycomputational system 6250 may be implemented in an object-orientedprogramming language. In an object-oriented programming language, dataand related methods can be grouped together or encapsulated to form anentity known as an object. All objects in an object-oriented programmingsystem belong to a class, which can be thought of as a category of likeobjects that describes the characteristics of those objects. Each objectis created as an instance of the class by a program. The objects maytherefore be said to have been instantiated from the class. The classsets out variables and methods for objects that belong to that class.The definition of the class does not itself create any objects. Theclass may define initial values for its variables, and it normallydefines the methods associated with the class (e.g., includes theprogram code which is executed when a method is invoked). The class maythereby provide all of the program code that will be used by objects inthe class, hence maximizing re-use of code that is shared by objects inthe class.

[0682] Turning now to FIG. 18, a block diagram of one embodiment ofcomputational system 6270 including processor 6293 coupled to a varietyof system components through bus bridge 6292 is shown. Other embodimentsare possible and contemplated. In the depicted system, main memory 6296is coupled to bus bridge 6292 through memory bus 6294, and graphicscontroller 6288 is coupled to bus bridge 6292 through AGP bus 6290.Finally, a plurality of PCI devices 6282 and 6284 are coupled to busbridge 6292 through PCI bus 6276. Secondary bus bridge 6274 may furtherbe provided to accommodate an electrical interface to one or more EISAor ISA devices 6280 through EISA/ISA bus 6278. Processor 6293 is coupledto bus bridge 6292 through CPU bus 6295 and to optional L2 cache 6297.

[0683] Bus bridge 6292 provides an interface between processor 6293,main memory 6296, graphics controller 6288, and devices attached to PCIbus 6276. When an operation is received from one of the devicesconnected to bus bridge 6292, bus bridge 6292 identifies the target ofthe operation (e.g., a particular device or, in the case of PCI bus6276, that the target is on PCI bus 6276). Bus bridge 6292 routes theoperation to the targeted device. Bus bridge 6292 generally translatesan operation from the protocol used by the source device or bus to theprotocol used by the target device or bus.

[0684] In addition to providing an interface to an ISA/EISA bus for PCIbus 6276, secondary bus bridge 6274 may further incorporate additionalfunctionality, as desired. An input/output controller (not shown),either external from or integrated with secondary bus bridge 6274, mayalso be included within computational system 6270 to provide operationalsupport for keyboard and mouse 6272 and for various serial and parallelports, as desired. An external cache unit (not shown) may further becoupled to CPU bus 6295 between processor 6293 and bus bridge 6292 inother embodiments. Alternatively, the external cache may be coupled tobus bridge 6292 and cache control logic for the external cache may beintegrated into bus bridge 6292. L2 cache 6297 is further shown in abackside configuration to processor 6293. It is noted that L2 cache 6297may be separate from processor 6293, integrated into a cartridge (e.g.,slot 1 or slot A) with processor 6293, or even integrated onto asemiconductor substrate with processor 6293.

[0685] Main memory 6296 is a memory in which application programs arestored and from which processor 6293 primarily executes. A suitable mainmemory 6296 comprises DRAM (Dynamic Random Access Memory). For example,a plurality of banks of SDRAM (Synchronous DRAM), DDR (Double Data Rate)SDRAM, or Rambus DRAM (RDRAM) may be suitable.

[0686] PCI devices 6282 and 6284 are illustrative of a variety ofperipheral devices such as, for example, network interface cards, videoaccelerators, audio cards, hard or floppy disk drives or drivecontrollers, SCSI (Small Computer Systems Interface) adapters, andtelephony cards. Similarly, ISA device 6280 is illustrative of varioustypes of peripheral devices, such as a modem, a sound card, and avariety of data acquisition cards such as GPIB or field bus interfacecards.

[0687] Graphics controller 6288 is provided to control the rendering oftext and images on display 6286. Graphics controller 6288 may embody atypical graphics accelerator generally known in the art to renderthree-dimensional data structures that can be effectively shifted intoand from main memory 6296. Graphics controller 6288 may therefore be amaster of AGP bus 6290 in that it can request and receive access to atarget interface within bus bridge 6292 to thereby obtain access to mainmemory 6296. A dedicated graphics bus accommodates rapid retrieval ofdata from main memory 6296. For certain operations, graphics controller6288 may generate PCI protocol transactions on AGP bus 6290. The AGPinterface of bus bridge 6292 may thus include functionality to supportboth AGP protocol transactions as well as PCI protocol target andinitiator transactions. Display 6286 is any electronic display uponwhich an image or text can be presented. A suitable display 6286includes a cathode ray tube (“CRT”), a liquid crystal display (“LCD”),etc.

[0688] It is noted that, while the AGP, PCI, and ISA or EISA buses havebeen used as examples in the above description, any bus architecturesmay be substituted as desired. It is further noted that computationalsystem 6270 may be a multiprocessing computational system includingadditional processors (e.g., processor 6291 shown as an optionalcomponent of computational system 6270). Processor 6291 may be similarto processor 6293. More particularly, processor 6291 may be an identicalcopy of processor 6293. Processor 6291 may be connected to bus bridge6292 via an independent bus (as shown in FIG. 18) or may share CPU bus6295 with processor 6293. Furthermore, processor 6291 may be coupled toan optional L2 cache 6298 similar to L2 cache 6297.

[0689]FIG. 19 illustrates a flow chart of a computer-implemented methodfor treating a hydrocarbon formation based on a characteristic of theformation. At least one characteristic 6370 may be input intocomputational system 6250. Computational system 6250 may process atleast one characteristic 6370 using a software executable to determine aset of operating conditions 6372 for treating the formation with in situprocess 6310. The software executable may process equations relating toformation characteristics and/or the relationships between formationcharacteristics. At least one characteristic 6370 may include, but isnot limited to, an overburden thickness, depth of the formation, type offormation, permeability, density, porosity, moisture content, and otherorganic maturity indicators, oil saturation, water saturation, volatilematter content, oil chemistry, ash content, net-to-gross ratio, carboncontent, hydrogen content, oxygen content, sulfur content, nitrogencontent, mineralology, soluble compound content, elemental composition,hydrogeology, water zones, gas zones, barren zones, mechanicalproperties, or top seal character. Computational system 6250 may be usedto control in situ process 6310 using determined set of operatingconditions 6372.

[0690]FIG. 20 illustrates a schematic of an embodiment used to controlan in situ conversion process (ICP) in formation 6600. Barrier well6602, monitor well 6604, production well 6606, and heater well 6608 maybe placed in formation 6600. Barrier well 6602 may be used to controlwater conditions within formation 6600. Monitoring well 6604 may be usedto monitor subsurface conditions in the formation, such as, but notlimited to, pressure, temperature, product quality, or fractureprogression. Production well 6606 may be used to produce formationfluids (e.g., oil, gas, and water) from the formation. Heater well 6608may be used to provide heat to the formation. Formation conditions suchas, but not limited to, pressure, temperature, fracture progression(monitored, for instance, by acoustical sensor data), and fluid quality(e.g., product quality or water quality) may be monitored through one ormore of wells 6602, 6604, 6606, and 6608.

[0691] Surface data such as pump status (e.g., pump on or off), fluidflow rate, surface pressure/temperature, and heater power may bemonitored by instruments placed at each well or certain wells.Similarly, subsurface data such as pressure, temperature, fluid quality,and acoustical sensor data may be monitored by instruments placed ateach well or certain wells. Surface data 6610 from barrier well 6602 mayinclude pump status, flow rate, and surface pressure/temperature.Surface data 6612 from production well 6606 may include pump status,flow rate, and surface pressure/temperature. Subsurface data 6614 frombarrier well 6602 may include pressure, temperature, water quality, andacoustical sensor data. Subsurface data 6616 from monitoring well 6604may include pressure, temperature, product quality, and acousticalsensor data. Subsurface data 6618 from production well 6606 may includepressure, temperature, product quality, and acoustical sensor data.Subsurface data 6620 from heater well 6608 may include pressure,temperature, and acoustical sensor data.

[0692] Surface data 6610 and 6612 and subsurface data 6614, 6616, 6618,and 6620 may be monitored as analog data 6621 from one or more measuringinstruments. Analog data 6621 may be converted to digital data 6623 inanalog-to-digital converter 6622. Digital data 6623 may be provided tocomputational system 6250. Alternatively, one or more measuringinstruments may provide digital data to computational system 6250.Computational system 6250 may include a distributed central processingunit (CPU). Computational system 6250 may process digital data 6623 tointerpret analog data 6621. Output from computational system 6250 may beprovided to remote display 6624, data storage 6626, display 6628, or toa surface facility 6630. Surface facility 6630 may include, for example,a hydrotreating plant, a liquid processing plant, or a gas processingplant. Computational system 6250 may provide digital output 6632 todigital-to-analog converter 6634. Digital-to-analog converter 6634 mayconverter digital output 6632 to analog output 6636.

[0693] Analog output 6636 may include instructions to control one ormore conditions of formation 6600. Analog output 6636 may includeinstructions to control the ICP within formation 6600. Analog output6636 may include instructions to adjust one or more parameters of theICP. The one or more parameters may include, but are not limited to,pressure, temperature, product composition, and product quality. Analogoutput 6636 may include instructions for control of pump status 6640 orflow rate 6642 at barrier well 6602. Analog output 6636 may includeinstructions for control of pump status 6644 or flow rate 6646 atproduction well 6606. Analog output 6636 may also include instructionsfor control of heater power 6648 at heater well 6608. Analog output 6636may include instructions to vary one or more conditions such as pumpstatus, flow rate, or heater power. Analog output 6636 may also includeinstructions to turn on and/or off pumps, heaters, or monitoringinstruments located at each well.

[0694] Remote input data 6638 may also be provided to computationalsystem 6250 to control conditions within formation 6600. Remote inputdata 6638 may include data used to adjust conditions of formation 6600.Remote input data 6638 may include data such as, but not limited to,electricity cost, gas or oil prices, pipeline tariffs, data fromsimulations, plant emissions, or refinery availability. Remote inputdata 6638 may be used by computational system 6250 to adjust digitaloutput 6632 to a desired value. In some embodiments, surface facilitydata 6650 may be provided to computational system 6250.

[0695] An in situ conversion process (ICP) may be monitored using afeedback control process. Conditions within a formation may be monitoredand used within the feedback control process. A formation being treatedusing an in situ conversion process may undergo changes in mechanicalproperties due to the conversion of solids and viscous liquids tovapors, fracture propagation (e.g., to overburden, underburden, watertables, etc.), increases in permeability or porosity and decreases indensity, moisture evaporation, and/or thermal instability of matrixminerals (leading to dehydration and decarbonation reactions and shiftsin stable mineral assemblages).

[0696] Remote monitoring techniques that will sense these changes inreservoir properties may include, but are not limited to, 4D (4dimension) time lapse seismic monitoring, 3D/3C (3 dimension/3component) seismic passive acoustic monitoring of fracturing, time lapse3D seismic passive acoustic monitoring of fracturing, electricalresistivity, thermal mapping, surface or downhole tilt meters, surveyingpermanent surface monuments, chemical sniffing or laser sensors forsurface gas abundance, and gravimetrics. More direct subsurface-basedmonitoring techniques may include high temperature downholeinstrumentation (such as thermocouples and other temperature sensingmechanisms, stress sensors, or instrumentation in the producer well todetect gas flows on a finely incremental basis).

[0697] In certain embodiments, a “base” seismic monitoring may beconducted, and then subsequent seismic results can be compared todetermine changes.

[0698] Simulation methods on a computer system may be used to model anin situ process for treating a formation. Simulations may determineand/or predict operating conditions (e.g., pressure, temperature, etc.),products that may be produced from the formation at given operatingconditions, and/or product characteristics (e.g., API gravity, aromaticto paraffin ratio, etc.) for the process. In certain embodiments, acomputer simulation may be used to model fluid mechanics (including masstransfer and heat transfer) and kinetics within the formation todetermine characteristics of products produced during heating of theformation. A formation may be modeled using commercially availablesimulation programs such as STARS, THERM, FLUENT, or CFX. In addition,combinations of simulation programs may be used to more accuratelydetermine or predict characteristics of the in situ process. Results ofthe simulations may be used to determine operating conditions within theformation prior to actual treatment of the formation. Results of thesimulations may also be used to adjust operating conditions duringtreatment of the formation based on a change in a property of theformation and/or a change in a desired property of a product producedfrom the formation.

[0699]FIG. 21 illustrates a flowchart of an embodiment of method 9470for modeling an in situ process for treating a relatively permeableformation using a computer system. Method 9470 may include providing atleast one property 9472 of the formation to the computer system.Properties of the formation may include, but are not limited to,porosity, permeability, saturation, thermal conductivity, volumetricheat capacity, compressibility, composition, and number and types ofphases in the formation. Properties may also include chemicalcomponents, chemical reactions, and kinetic parameters. At least oneoperating condition 9474 of the process may also be provided to thecomputer system. For instance, operating conditions may include, but arenot limited to, pressure, temperature, heating rate, heat input rate,process time, weight percentage of gases, production characteristics(e.g., flow rates, locations, compositions), and peripheral waterrecovery or injection. In addition, operating conditions may includecharacteristics of the well pattern such as producer well location,producer well orientation, ratio of producer wells to heater wells,heater well spacing, type of heater well pattern, heater wellorientation, and distance between an overburden and horizontal heaterwells.

[0700] Furthermore, a method may include assessing at least one processcharacteristic 9478 of the in situ process using simulation method 9476on the computer system. At least one process characteristic may beassessed as a function of time from at least one property of theformation and at least one operating condition. Process characteristicsmay include properties of a produced fluid such as API gravity, olefincontent, carbon number distribution, ethene to ethane ratio, atomiccarbon to hydrogen ratio, and ratio of non condensable hydrocarbons tocondensable hydrocarbons (gas/oil ratio). Process characteristics mayalso include a pressure and temperature in the formation, total massrecovery from the formation, and/or production rate of fluid producedfrom the formation.

[0701] In some embodiments, a simulation method may include a numericalsimulation method used/performed on the computer system. The numericalsimulation method may employ finite difference methods to solve fluidmechanics, heat transfer, and chemical reaction equations as a functionof time. A finite difference method may use a body-fitted grid systemwith unstructured grids to model a formation. An unstructured gridemploys a wide variety of shapes to model a formation geometry, incontrast to a structured grid. A body-fitted finite differencesimulation method may calculate fluid flow and heat transfer in aformation. Heat transfer mechanisms may include conduction, convection,and radiation. The body-fitted finite difference simulation method mayalso be used to treat chemical reactions in the formation. Simulationswith a finite difference simulation method may employ closed valuethermal conduction equations to calculate heat transfer and temperaturedistributions in the formation. A finite difference simulation methodmay determine values for heat injection rate data.

[0702] In an embodiment, a body-fitted finite difference simulationmethod may be well suited for simulating systems that include sharpinterfaces in physical properties or conditions. In general, abody-fitted finite difference simulation method may be more accurate, incertain circumstances, than space-fitted methods due to the use offiner, unstructured grids in body-fitted methods. For instance, it maybe advantageous to use a body-fitted finite difference simulation methodto calculate heat transfer in a heater well and in the region near orclose to a heater well. The temperature profile in and near a heaterwell may be relatively sharp. A region near a heater well may bereferred to as a “near wellbore region.” The size or radius of a nearwellbore region may depend on the type of formation. A general criteriafor determining or estimating the radius of a “near wellbore region” maybe a distance at which heat transfer by the mechanism of convectioncontributes significantly to overall heat transfer. Heat transfer in thenear wellbore region is typically limited to contributions fromconductive and/or radiative heat transfer. Convective heat transfertends to contribute significantly to overall heat transfer at locationswhere fluids flow within the formation (i.e., convective heat transferis significant where the flow of mass contributes to heat transfer).

[0703] In general, the radius of a near wellbore region in a formationdecreases with both increasing convection and increasing variation ofthermal properties with temperature in the formation. For example, arelatively permeable formation may have a relatively small near wellboreregion due to the contribution of convection for heat transfer and alarge variation of thermal properties with temperature. In oneembodiment, the near wellbore region in a relatively permeable formationmay have a radius of about 1 m to about 2 m. In other embodiments, theradius may be between about 2 m and about 4 m.

[0704] In a simulation of a heater well and near wellbore region, abody-fitted finite difference simulation method may calculate the heatinput rate that corresponds to a given temperature in a heater well. Themethod may also calculate the temperature distributions both inside thewellbore and at the near wellbore region.

[0705] CFX supplied by AEA Technologies in the United Kingdom is anexample of a commercially available body-fitted finite differencesimulation method. FLUENT is another commercially available body-fittedfinite difference simulation method from FLUENT, Inc. located inLebanon, N.H. FLUENT may simulate models of a formation that includeporous media and heater wells. The porous media models may include oneor more materials and/or phases with variable fractions. The materialsmay have user-specified temperature dependent thermal properties anddensities. The user may also specify the initial spatial distribution ofthe materials in a model. In one modeling scheme of a porous media, acombustion reaction may only involve a reaction between carbon andoxygen. In a model of hydrocarbon combustion, the volume fraction andporosity of the formation tend to decrease. In addition, a gas phase maybe modeled by one or more species in FLUENT, for example, nitrogen,oxygen, and carbon dioxide.

[0706] In an embodiment, the simulation method may include a numericalsimulation method on a computer system that uses a space-fitted finitedifference method with structured grids. The space-fitted finitedifference simulation method may be a reservoir simulation method. Areservoir simulation method may calculate fluid mechanics, massbalances, heat transfer, and/or kinetics in the formation. A reservoirsimulation method may be particularly useful for modeling multiphaseporous media in which convection (e.g., the flow of hot fluids) is arelatively important mechanism of heat transfer.

[0707] STARS is an example of a reservoir simulation method provided byComputer Modeling Group, Ltd. of Alberta, Canada STARS is designed forsimulating steam flood, steam cycling, steam-with-additives, dry and wetcombustion, along with many types of chemical additive processes, usinga wide range of grid and porosity models in both field and laboratoryscales. STARS includes options such as thermal applications, steaminjection, fireflood, horizontal wells, dual porosity/permeability,directional permeability, and flexible grids. STARS allows for complextemperature dependent models of thermal and physical properties. STARSmay also simulate pressure dependent chemical reactions. STARS maysimulate a formation using a combination of structured space-fittedgrids and unstructured body-fitted grids. Additionally, THERM is anexample of a reservoir simulation method provided by Scientific SoftwareIntercomp.

[0708] In certain embodiments, a simulation method may use properties ofa formation. In general, the properties of a formation for a model of anin situ process depend on the type of formation.

[0709] An embodiment of a model of a tar sands formation may include aninert mineral matter phase and a fluid phase that includes heavyhydrocarbons. In an embodiment, the porosity of a tar sands formationmay be modeled as a function of the pressure of the formation and itsmechanical properties. For example, the porosity, φ, at a pressure, P,in a tar sands formation may be given by EQN. 2:

φ=φ_(ref) exp[c(P−P _(ref))](2)

[0710] where P_(ref) is a reference pressure, φ_(ref) is the porosity atthe reference pressure, and c is the formation compressibility.

[0711] Some embodiments of a simulation method may require an initialpermeability of a formation and a relationship for the dependence ofpermeability on conditions of the formation. An initial permeability ofa formation may be determined from experimental measurements of a sample(e.g., a core sample) of a formation.

[0712] In some embodiments, the porosity of a formation may be used tomodel the change in permeability of the formation during a simulation.In one embodiment, the dependence of porosity on permeability may bedescribed by an analytical relationship. For example, the effect ofpyrolysis on permeability, K, may be governed by a Carman-Kozeny typeformula shown in EQN. 3:

[0713]K(φ_(f))=K ₀(φ_(f)/φ_(f,0))^(CKpower)[(1−φ_(f,0))/(1−φ_(f))]²  (3)

[0714] where φ_(f) is the current fluid porosity, φ_(f,0) is the initialfluid porosity, K₀ is the permeability at initial fluid porosity, andCKpower is a user-defined exponent. The value of CKpower may be fittedby matching or approximating the pressure gradient in an experiment in aformation. The porosity-permeability relationship 9350 is plotted inFIG. 22 for a value of the initial porosity of 0.935 millidarcy andCKpower=0.95.

[0715] Alternatively, in some formations, such as a tar sands formation,the permeability dependence may be expressed as shown in EQN. 4:

K(φ_(f))=K ₀ ×exp[k _(mul)×(φ_(f)−φ_(f,0))/(1−φ_(f,0))]  (4)

[0716] where K₀ and φ_(f,0) are the initial permeability and porosity,and k_(mul) is a user-defined grid dependent permeability multiplier. Inother embodiments, a tabular relationship rather than an analyticalexpression may be used to model the dependence of permeability onporosity. In addition, the ratio of vertical to horizontal permeabilityfor tar sands formations may be determined from experimental data.

[0717] In certain embodiments, the thermal conductivity of a model of aformation may be expressed in terms of the thermal conductivities ofconstituent materials. For example, the thermal conductivity may beexpressed in terms of solid phase components and fluid phase components.One or more fluid phases in the formations may include, for example, awater phase, an oil phase, and a gas phase. The thermal conductivityalso changes with temperature due to the change in composition of thefluid phase and porosity.

[0718] In some embodiments, a model may take into account the effect ofdifferent geological strata on properties of the formation. A propertyof a formation may be calculated for a given mineralogical composition.For example, the thermal conductivity of a model of a tar sandsformation may be calculated from EQN. 5: $\begin{matrix}{k_{t\quad h} = {k_{f}^{\varphi}{\prod\limits_{i = 1}^{n}k_{i}^{c_{i}{({1 - \varphi})}}}}} & (5)\end{matrix}$

[0719] where k^(φ) _(f) is the thermal conductivity of the fluid phaseat porosity φ, k_(i) is the thermal conductivity of geological layer i,and c_(i) is the compressibility of geological layer i.

[0720] In an embodiment, the volumetric heat capacity, ρ_(b)C_(p), mayalso be modeled as a direct function of temperature. However, thevolumetric heat capacity also depends on the composition of theformation material through the density, which is affected bytemperature.

[0721] In one embodiment, properties of the formation may include one ormore phases with one or more chemical components. For example, fluidphases may include water, oil, and gas. Solid phases may include mineralmatter and organic matter. Each of the fluid phases in an in situprocess may include a variety of chemical components such ashydrocarbons, H₂, CO₂, etc. The chemical components may be products ofone or more chemical reactions, such as pyrolysis reactions, that occurin the formation. Some embodiments of a model of an in situ process mayinclude modeling individual chemical components known to be present in aformation. However, inclusion of chemical components in a model of an insitu process may be limited by available experimental composition andkinetic data for the components. In addition, a simulation method mayalso place numerical and solution time limitations on the number ofcomponents that may be modeled.

[0722] In some embodiments, one or more chemical components may bemodeled as a single component called a pseudo-component. In certainembodiments, the oil phase may be modeled by two volatilepseudo-components, a light oil and a heavy oil. The oil and at leastsome of the gas phase components are generated by pyrolysis of organicmatter in the formation. The light oil and the heavy oil may be modeledas having an API gravity that is consistent with laboratory orexperimental field data. For example, the light oil may have an APIgravity of between about 20° and about 70°. The heavy oil may have anAPI gravity less than about 200.

[0723] In some embodiments, hydrocarbon gases in a formation of one ormore carbon numbers may be modeled as a single pseudo-component. Inother embodiments, non-hydrocarbon gases and hydrocarbon gases may bemodeled as a single component. For example, hydrocarbon gases between acarbon number of one to a carbon number of five and nitrogen andhydrogen sulfide may be modeled as a single component. In someembodiments, the multiple components modeled as a single component haverelatively similar molecular weights. A molecular weight of thehydrocarbon gas pseudo-component may be set such that thepseudo-component is similar to a hydrocarbon gas generated in alaboratory pyrolysis experiment at a specified pressure.

[0724] In some embodiments of an in situ process, the composition of thegenerated hydrocarbon gas may vary with pressure. As pressure increases,the ratio of a higher molecular weight component to a lower molecularcomponent tends to increase. For example, as pressure increases, theratio of hydrocarbon gases with carbon numbers between about three andabout five to hydrocarbon gases with one and two carbon numbers tends toincrease. Consequently, the molecular weight of the pseudo-componentthat models a mixture of component gases may vary with pressure.

[0725] In one embodiment, a model of an in situ process may include oneor more chemical reactions. A number of chemical reactions are known tooccur in an in situ process for a relatively permeable formation. Thechemical reactions may belong to one of several categories of reactions.The categories may include, but not be limited to, generation ofpre-pyrolysis water and carbon dioxide, generation of hydrocarbons,coking and cracking of hydrocarbons, formation of synthesis gas, andcombustion and oxidation of coke.

[0726] In one embodiment, the rate of change of the concentration ofspecies X due to a chemical reaction, for example:

X→products  (I)

[0727] may be expressed in terms of a rate law:

d[X]/dt=−k [X] ^(n)  (II)

[0728] Species X in the chemical reaction undergoes chemicaltransformation to the products. [X] is the concentration of species X, tis the time, k is the reaction rate constant, and n is the order of thereaction. The reaction rate constant, k, may be defined by the Arrheniusequation:

k=A exp[−E _(a) /RT]  (III)

[0729] where A is the frequency factor, E_(a) is the activation energy,R is the universal gas constant, and T is the temperature. Kineticparameters, such as k, A, E_(a), and n, may be determined fromexperimental measurements. A simulation method may include one or morerate laws for assessing the change in concentration of species in an insitu process as a function of time. Experimentally determined kineticparameters for one or more chemical reactions may be used as input tothe simulation method.

[0730] In some embodiments, the number and categories of reactions in amodel of an in situ process may depend on the availability ofexperimental kinetic data and/or numerical limitations of a simulationmethod. Generally, chemical reactions and kinetic parameters for a modelmay be chosen such that simulation results match or approximatequantitative and qualitative experimental trends.

[0731] In some embodiments, reactions that model the generation ofpre-pyrolysis water and carbon dioxide account for the bound water,carbon dioxide, and carbon monoxide generated in a temperature rangebelow a pyrolysis temperature. For example, pre-pyrolysis water may begenerated from hydrated mineral matter. In one embodiment, thetemperature range may be between about 100° C. and about 270° C. Inother embodiments, the temperature range may be between about 80° C. andabout 300° C. Reactions in the temperature range below a pyrolysistemperature may account for between about 45% and about 60% of the totalwater generated and up to about 30% of the total carbon dioxide observedin laboratory experiments of pyrolysis.

[0732] In an embodiment, the pressure dependence of the chemicalreactions may be modeled. To account for the pressure dependence, asingle reaction with variable stoichiometric coefficients may be used tomodel the generation of pre-pyrolysis fluids. Alternatively, thepressure dependence may be modeled with two or more reactions withpressure dependent kinetic parameters such as frequency factors.

[0733] For example, experimental results indicate that the reaction thatgenerates pre-pyrolysis fluids from a formation is a function ofpressure. The amount of water generated generally decreases withpressure while the amount of carbon dioxide generated generallyincreases with pressure. In an embodiment, the generation ofpre-pyrolysis fluids may be modeled with two reactions to account forthe pressure dependence. One reaction may be dominant at high pressureswhile the other may be prevalent at lower pressures.

[0734] In an embodiment, a reaction enthalpy may be used by a simulationmethod such as STARS to assess the thermodynamic properties of aformation. The reaction enthalpy is a negative number if a chemicalreaction is endothermic and positive if a chemical reaction isexothermic.

[0735] In other embodiments, the generation of hydrocarbons in apyrolysis temperature range in a formation may be modeled with one ormore reactions. One or more reactions may model the amount ofhydrocarbon fluids and carbon residue that are generated in a pyrolysistemperature range. Hydrocarbons generated may include light oil, heavyoil, and non-condensable gases. Pyrolysis reactions may also generatewater, H₂, and CO₂.

[0736] Experimental results indicate that the composition of productsgenerated in a pyrolysis temperature range may depend on operatingconditions such as pressure. For example, the production rate ofhydrocarbons generally decreases with pressure. In addition, the amountof produced hydrogen gas generally decreases substantially withpressure, the amount of carbon residue generally increases withpressure, and the amount of condensable hydrocarbons generally decreaseswith pressure. Furthermore, the amount of non-condensable hydrocarbonsgenerally increases with pressure such that the sum of condensablehydrocarbons and non-condensable hydrocarbons generally remainsapproximately constant with a change in pressure. In addition, the APIgravity of the generated hydrocarbons increases with pressure.

[0737] In an embodiment, the pressure dependence of the production ofhydrocarbons may be taken into account by a set of cracking/cokingreactions. Alternatively, pressure dependence of hydrocarbon productionmay be modeled by hydrocarbon generation reactions withoutcracking/coking reactions.

[0738] In one embodiment, one or more reactions may model the crackingand coking in a formation. Cracking reactions involve the reaction ofcondensable hydrocarbons (e.g., light oil and heavy oil) to form lightercompounds (e.g., light oil and non-condensable gases) and carbonresidue. The coking reactions model the polymerization and condensationof hydrocarbon molecules. Coking reactions lead to formation of char,lower molecular weight hydrocarbons, and hydrogen. Gaseous hydrocarbonsmay undergo coking reactions to form carbon residue and H₂. Coking andcracking may account for the deposition of coke in the vicinity ofheater wells where the temperature may be substantially greater than apyrolysis temperature.

[0739] In addition, reactions may model the generation of water at atemperature below or within a pyrolysis temperature range and thegeneration of hydrocarbons at a temperature in a pyrolysis temperaturerange in a formation. Coking and cracking in a formation may be modeledby one or more reactions in both the liquid phase and the gas phase.

[0740] In certain embodiments, the generation of synthesis gas in aformation may be modeled by one or more reactions In an embodiment,pressure dependence of the reactions in a formation may be modeled, forexample, with pressure dependent frequency-factors.

[0741] In one embodiment, a combustion and oxidation reaction of coke tocarbon dioxide may be modeled in a formation. For example, the molarstoichiometry of a reaction according to one embodiment may be:

0.9442 mol char+1.0 mol O₂⇄1.0 mol CO₂  (6)

[0742] Experimentally derived kinetic parameters include a frequencyfactor of 1.0×10⁴ (day)⁻¹, an activation energy of 58,614 KJ/mole, anorder of 1, and a reaction enthalpy of 427,977 KJ/mole.

[0743] In some embodiments, a model of a tar sands formation may bemodeled with the following components: bitumen (heavy oil), light oil,HCgas1, HCgas2, water, char, and prechar. According to one embodiment,an in situ process in a tar sands formation may be modeled by at leasttwo reactions:

Bitumen→light oil+HCgas1+H₂O+prechar  (7)

Prechar→HCgas2+H₂O+char  (8)

[0744] Reaction 7 models the pyrolysis of bitumen to oil and gascomponents. In one embodiment, Reaction (7) may be modeled as a 2^(nd)order reaction and Reaction (8) may be modeled as a 7^(th) orderreaction. In one embodiment, the reaction enthalpy of Reactions (7) and(8) may be zero.

[0745] In an embodiment, a method of modeling an in situ process oftreating a relatively permeable formation using a computer system mayinclude simulating a heat input rate to the formation from two or moreheat sources. FIG. 23 illustrates method 9360 for simulating heattransfer in a formation. Simulation method 9361 may simulate heat inputrate 9368 from two or more heat sources in the formation. For example,the simulation method may be a body-fitted finite difference simulationmethod. The heat may be allowed to transfer from the heat sources to aselected section of the formation. In an embodiment, the superpositionof heat from the two or more heat sources may pyrolyze at least somehydrocarbons within the selected section of the formation. In oneembodiment, two or more heat sources may be simulated with a model ofheat sources with symmetry boundary conditions.

[0746] In some embodiments, the method may further include providing atleast one desired parameter 9366 of the in situ process to the computersystem. For example, the desired parameter may be a desired temperaturein the formation. In particular, the desired parameter may be a maximumtemperature at specific locations in the formation. In addition, thedesired parameter may be a desired heating rate or a desired productcomposition. Desired parameters may also include other parameters suchas a desired pressure, process time, production rate, time to obtain agiven production rate, and product composition. Process characteristics9362 determined by simulation method 9361 may be compared 9364 to atleast one desired parameter 9366. The method may further includecontrolling 9363 the heat input rate from the heat sources (or someother process parameter) to achieve at least one desired parameter.Consequently, the heat input rate from the two or more heat sourcesduring a simulation may be time dependent.

[0747] In an embodiment, heat injection into a formation may beinitiated by imposing a constant flux per unit area at the interfacebetween a heater and the formation. When a point in the formation, suchas the interface, reaches a specified maximum temperature, the heat fluxmay be varied to maintain the maximum temperature. The specified maximumtemperature may correspond to the maximum temperature allowed for aheater well casing (e.g., a maximum operating temperature for themetallurgy in the heater well). In one embodiment, the maximumtemperature may be between about 600° C. and about 700° C. In otherembodiments, the maximum temperature may be between about 700° C. andabout 800° C. In some embodiments, the maximum temperature may begreater than about 800° C.

[0748]FIG. 24 illustrates a model for simulating a heat transfer rate ina formation. Model 9370 represents an aerial view of {fraction(1/12)}^(th) of a seven spot heater pattern in a formation. The patternis composed of body-fitted grid elements 9371. The model includeshorizontal heater 9372 and producer 9374. A pattern of heaters in aformation is modeled by imposing symmetry boundary conditions. Theelements near the heaters and in the region near the heaters aresubstantially smaller than other portions of the formation to moreeffectively model a steep temperature profile.

[0749] In one embodiment, an in situ process may be modeled with morethan one simulation methods. FIG. 25 illustrates a flowchart of anembodiment of method 8630 for modeling an in situ process for treating arelatively permeable formation using a computer system. At least oneheat input property 8632 may be provided to the computer system. Thecomputer system may include first simulation method 8634. At least oneheat input property 8632 may include a heat transfer property of theformation. For example, the heat transfer property of the formation mayinclude heat capacities or thermal conductivities of one or morecomponents in the formation. In certain embodiments, at least one heatinput property 8632 includes an initial heat input property of theformation. Initial heat input properties may also include, but are notlimited to, volumetric heat capacity, thermal conductivity, porosity,permeability, saturation, compressibility, composition, and the numberand types of phases. Properties may also include chemical components,chemical reactions, and kinetic parameters.

[0750] In certain embodiments, first simulation method 8634 may simulateheating of the formation. For example, the first simulation method maysimulate heating the wellbore and the near wellbore region. Simulationof heating of the formation may assess (i.e., estimate, calculate, ordetermine) heat injection rate data 8636 for the formation. In oneembodiment, heat injection rate data may be assessed to achieve at leastone desired parameter of the formation, such as a desired temperature orcomposition of fluids produced from the formation. First simulationmethod 8634 may use at least one heat input property 8632 to assess heatinjection rate data 8636 for the formation. First simulation method 8634may be a numerical simulation method. The numerical simulation may be abody-fitted finite difference simulation method. In certain embodiments,first simulation method 8634 may use at least one heat input property8632, which is an initial heat input property. First simulation method8634 may use the initial heat input property to assess heat inputproperties at later times during treatment (e.g., heating) of theformation.

[0751] Heat injection rate data 8636 may be used as input into secondsimulation method 8640. In some embodiments, heat injection rate data8636 may be modified or altered for input into second simulation method8640. For example, heat injection rate data 8636 may be modified as aboundary condition for second simulation method 8640. At least oneproperty 8638 of the formation may also be input for use by secondsimulation method 8640. Heat injection rate data 8636 may include atemperature profile in the formation at any time during heating of theformation. Heat injection rate data 8636 may also include heat flux datafor the formation. Heat injection rate data 8636 may also includeproperties of the formation.

[0752] Second simulation method 8640 may be a numerical simulationand/or a reservoir simulation method. In certain embodiments, secondsimulation method 8640 may be a space-fitted finite differencesimulation (e.g., STARS). Second simulation method 8640 may includesimulations of fluid mechanics, mass balances, and/or kinetics withinthe formation. The method may further include providing at least oneproperty 8638 of the formation to the computer system. At least oneproperty 8638 may include chemical components, reactions, and kineticparameters for the reactions that occur within the formation. At leastone property 8638 may also include other properties of the formationsuch as, but not limited to, permeability, porosities, and/or a locationand orientation of heat sources, injection wells, or production wells.

[0753] Second simulation method 8640 may assess at least one processcharacteristic 8642 as a function of time based on heat injection ratedata 8636 and at least one property 8638. In some embodiments, secondsimulation method 8640 may assess an approximate solution for at leastone process characteristic 8642. The approximate solution may be acalculated estimation of at least one process characteristic 8642 basedon the heat injection rate data and at least one property. Theapproximate solution may be assessed using a numerical method in secondsimulation method 8640. At least one process characteristic 8642 mayinclude one or more parameters produced by treating a relativelypermeable formation in situ. For example, at least one processcharacteristic 8642 may include, but is not limited to, a productionrate of one or more produced fluids, an API gravity of a produced fluid,a weight percentage of a produced component, a total mass recovery fromthe formation, and operating conditions in the formation such aspressure or temperature.

[0754] In some embodiments, first simulation method 8634 and secondsimulation method 8640 may be used to predict process characteristicsusing parameters based on laboratory data. For example, experimentallybased parameters may include chemical components, chemical reactions,kinetic parameters, and one or more formation properties. Thesimulations may further be used to assess operating conditions that canbe used to produce desired properties in fluids produced from theformation. In additional embodiments, the simulations may be used topredict changes in process characteristics based on changes in operatingconditions and/or formation properties.

[0755] In certain embodiments, one or more of the heat input propertiesmay be initial values of the heat input properties. Similarly, one ormore of the properties of the formation may be initial values of theproperties. The heat input properties and the reservoir properties maychange during a simulation of the formation using the first and secondsimulation methods. For example, the chemical composition, porosity,permeability, volumetric heat capacity, thermal conductivity, and/orsaturation may change with time. Consequently, the heat input rateassessed by the first simulation method may not be adequate input forthe second simulation method to achieve a desired parameter of theprocess. In some embodiments, the method may further include assessingmodified heat injection rate data at a specified time of the secondsimulation. At least one heat input property 8641 of the formationassessed at the specified time of the second simulation method may beused as input by first simulation method 8634 to calculate the modifiedheat input data. Alternatively, the heat input rate may be controlled toachieve a desired parameter during a simulation of the formation usingthe second simulation method.

[0756] In some embodiments, one or more model parameters for input intoa simulation method may be based on laboratory or field test data of anin situ process for treating a relatively permeable formation. FIG. 26illustrates a flow chart of an embodiment of method 9390 for calibratingmodel parameters to match or approximate laboratory or field data for anin situ process. The method may include providing one or more modelparameters 9392 for the in situ process. The model parameters mayinclude properties of the formation. In addition, the model parametersmay also include relationships for the dependence of properties on thechanges in conditions, such as temperature and pressure, in theformation. For example, model parameters may include a relationship forthe dependence of porosity on pressure in the formation. Modelparameters may also include an expression for the dependence ofpermeability on porosity. Model parameters may include an expression forthe dependence of thermal conductivity on composition of the formation.In addition, model parameters may include chemical components, thenumber and types of reactions in the formation, and kinetic parameters.Kinetic parameters may include the order of a reaction, activationenergy, reaction enthalpy, and frequency factor.

[0757] In some embodiments, the method may include assessing one or moresimulated process characteristics 9396 based on the one or more modelparameters. Simulated process characteristics 9396 may be assessed usingsimulation method 9394. Simulation method 9394 may be a body-fittedfinite difference simulation method. Alternatively, simulation method9394 may be a reservoir simulation method.

[0758] In an embodiment, simulated process characteristics 9396 may becompared 9398 to real process characteristics 9400. Real processcharacteristics may be process characteristics obtained from laboratoryor field tests of an in situ process. Comparing process characteristicsmay include comparing the simulated process characteristics with thereal process characteristics as a function of time. Differences betweena simulated process characteristic and a real process characteristic maybe associated with one or more model parameters. For example, a higherratio of gas to oil of produced fluids from a real in situ process maybe due to a lack of pressure dependence of kinetic parameters. Themethod may further include modifying 9399 the one or more modelparameters such that at least one simulated process characteristicmatches or approximates at least one real process characteristic. One ormore model parameters may be modified to account for a differencebetween a simulated process characteristic and a real processcharacteristic. For example, an additional chemical reaction may beadded to account for pressure dependence or a discrepancy of an amountof a particular component in produced fluids.

[0759] Some embodiments may include assessing one or more modifiedsimulated process characteristics from simulation method 9394 based onmodified model parameters 9397. Modified model parameters may includeone or both of model parameters 9392 that have been modified and thathave not been modified. In an embodiment, the simulation method may usemodified model parameters 9397 to assess at least one operatingcondition of the in situ process to achieve at least one desiredparameter.

[0760] Method 9390 may be used to calibrate model parameters forgeneration reactions of pre-pyrolysis fluids and generation ofhydrocarbons from pyrolysis. For example, field test results may show alarger amount of H₂ produced from the formation than the simulationresults. The discrepancy may be due to the generation of synthesis gasin the formation in the field test. Synthesis gas may be generated fromwater in the formation, particularly near heater wells. The temperaturesnear heater wells may approach a synthesis gas generating temperaturerange even when the majority of the formation is below synthesis gasgenerating temperatures. Therefore, the model parameters for thesimulation method may be modified to include some synthesis gasreactions.

[0761] In addition, model parameters may be calibrated to account forthe pressure dependence of the production of low molecular weighthydrocarbons in a formation. The pressure dependence may arise in bothlaboratory and field scale experiments. As pressure increases, fluidstend to remain in a laboratory vessel or a formation for longer periodsof time. The fluids tend to undergo increased cracking and/or cokingwith increased residence time in the laboratory vessel or the formation.As a result, larger amounts of lower molecular weight hydrocarbons maybe generated. Increased cracking of fluids may be more pronounced in afield scale experiment (as compared to a lab experiment, or as comparedto calculated cracking) due to longer residence times since fluids maybe required to pass through significant distances (e.g., tens of meters)of formation before being produced from a formation.

[0762] Simulations may be used to calibrate kinetics parameters thataccount for the pressure dependence. For example, pressure dependencemay be accounted for by introducing cracking and coking reactions into asimulation. The reactions may include pressure dependent kineticparameters to account for the pressure dependence. Kinetics parametersmay be chosen to match or approximate hydrocarbon production reactionsparameters from experiments.

[0763] In certain embodiments, a simulation method based on a set ofmodel parameters may be used to design an in situ process. A field testof an in situ process based on the design may be used to calibrate themodel parameters. FIG. 27 illustrates a flowchart of an embodiment ofmethod 9405 for calibrating model parameters. Method 9405 may includeassessing at least one operating condition 9414 of the in situ processusing simulation method 9410 based on one or more model parameters.Operating conditions may include pressure, temperature, heating rate,heat input rate, process time, weight percentage of gases, peripheralwater recovery or injection. Operating conditions may also includecharacteristics of the well pattern such as producer well location,producer well orientation, ratio of producer wells to heater wells,heater well spacing, type of heater well pattern, heater wellorientation, and distance between an overburden and horizontal heaterwells. In one embodiment, at least one operating condition may beassessed such that the in situ process achieves at least one desiredparameter.

[0764] In some embodiments, at least one operating condition 9414 may beused in real in situ process 9418. In an embodiment, the real in situprocess may be a field test, or a field operation, operating with atleast one operating condition. The real in situ process may have one ormore real process characteristics 9420. Simulation method 9410 mayassess one or more simulated process characteristics 9412. In anembodiment, simulated process characteristics 9412 may be compared 9416to real process characteristics 9420. The one or more model parametersmay be modified such that at least one simulated process characteristic9412 from a simulation of the in situ process matches or approximates atleast one real process characteristic 9420 from the in situ process. Thein situ process may then be based on at least one operating condition.The method may further include assessing one or more modified simulatedprocess characteristics based on the modified model parameters 9417. Insome embodiments, simulation method 9410 may be used to control the insitu process such that the in situ process has at least one desiredparameter.

[0765] In one embodiment, a first simulation method may be moreeffective than a second simulation method in assessing processcharacteristics under a first set of conditions. Alternatively, thesecond simulation method may be more effective in assessing processcharacteristics under a second set of conditions. A first simulationmethod may include a body-fitted finite difference simulation method. Afirst set of conditions may include, for example, a relatively sharpinterface in an in situ process. In an embodiment, a first simulationmethod may use a finer grid than a second simulation method. Thus, thefirst simulation method may be more effective in modeling a sharpinterface. A sharp interface refers to a relatively large change in oneor more process characteristics in a relatively small region in theformation. A sharp interface may include a relatively steep temperaturegradient that may exist in a near wellbore region of a heater well. Arelatively steep gradient in pressure and composition, due to pyrolysis,may also exist in the near wellbore region. A sharp interface may alsobe present at a combustion or reaction front as it propagates through aformation. A steep gradient in temperature, pressure, and compositionmay be present at a reaction front.

[0766] In certain embodiments, a second simulation method may include aspace-fitted finite difference simulation method such as a reservoirsimulation method. A second set of conditions may include conditions inwhich heat transfer by convection is significant. In addition, a secondset of conditions may also include condensation of fluids in aformation.

[0767] In some embodiments, model parameters for the second simulationmethod may be calibrated such that the second simulation methodeffectively assesses process characteristics under both the first setand the second set of conditions. FIG. 28 illustrates a flow chart of anembodiment of method 9430 for calibrating model parameters for a secondsimulation method using a first simulation method. Method 9430 mayinclude providing one or more model parameters 9431 to a computersystem. One or more first process characteristics 9434 based on one ormore model parameters 9431 may be assessed using first simulation method9432 in memory on the computer system. First simulation method 9432 maybe a body-fitted finite difference simulation method. The modelparameters may include relationships for the dependence of propertiessuch as porosity, permeability, thermal conductivity, and heat capacityon the changes in conditions (e.g., temperature and pressure) in theformation. In addition, model parameters may include chemicalcomponents, the number and types of reactions in the formation, andkinetic parameters. Kinetic parameters may include the order of areaction, activation energy, reaction enthalpy, and frequency factor.Process characteristics may include, but are not limited to, atemperature profile, pressure, composition of produced fluids, and avelocity of a reaction or combustion front.

[0768] In certain embodiments, one or more second processcharacteristics 9440 based on one or more model parameters 9431 may beassessed using second simulation method 9438. Second simulation method9438 may be a space-fitted finite difference simulation method, such asa reservoir simulation method. One or more first process characteristics9434 may be compared 9436 to one or more second process characteristics9440. The method may further include modifying one or more modelparameters 9431 such that at least one first process characteristic 9434matches or approximates at least one second process characteristic 9440.For example, the order or the activation energy of the one or morechemical reactions may be modified to account for differences betweenthe first and second process characteristics. In addition, a singlereaction may be expressed as two or more reactions. In some embodiments,one or more third process characteristics based on the one or moremodified model parameters 9442 may be assessed using the secondsimulation method.

[0769] In one embodiment, simulations of an in situ process for treatinga relatively permeable formation may be used to design and/or control areal in situ process. Design and/or control of an in situ process mayinclude assessing at least one operating condition that achieves adesired parameter of the in situ process. FIG. 29 illustrates a flowchart of an embodiment of method 9450 for the design and/or control ofan in situ process. The method may include providing to the computersystem one or more values of at least one operating condition 9452 ofthe in situ process for use as input to simulation method 9454. Thesimulation method may be a space-fitted finite difference simulationmethod such as a reservoir simulation method or it may be a body-fittedsimulation method such as FLUENT. At least one operating condition mayinclude, but is not limited to, pressure, temperature, heating rate,heat input rate, process time, weight percentage of gases, peripheralwater recovery or injection, production rate, and time to reach a givenproduction rate. In addition, operating conditions may includecharacteristics of the well pattern such as producer well location,producer well orientation, ratio of producer wells to heater wells,heater well spacing, type of heater well pattern, heater wellorientation, and distance between an overburden and horizontal heaterwells.

[0770] In one embodiment, the method may include assessing one or morevalues of at least one process characteristic 9456 corresponding to oneor more values of at least one operating condition 9452 from one or moresimulations using simulation method 9454. In certain embodiments, avalue of at least one process characteristic may include the processcharacteristic as a function of time. A desired value of at least oneprocess characteristic 9460 for the in situ process may also be providedto the computer system. An embodiment of the method may further includeassessing 9458 desired value of at least one operating condition 9462 toachieve desired value of at least one process characteristic 9460.Desired value of at least one operating condition 9462 may be assessedfrom the values of at least one process characteristic 9456 and valuesof at least one operating condition 9452. For example, desired value9462 may be obtained by interpolation of values 9456 and values 9452. Insome embodiments, a value of at least one process characteristic may beassessed from the desired value of at least one operating condition 9462using simulation method 9454. In some embodiments, an operatingcondition to achieve a desired parameter may be assessed by comparing aprocess characteristic as a function of time for different operatingconditions. In an embodiment, the method may include operating the insitu system using the desired value of at least one additional operatingcondition.

[0771] In an alternate embodiment, a desired value of at least oneoperating condition to achieve the desired value of at least one processcharacteristic may be assessed by using a relationship between at leastone process characteristic and at least one operating condition of thein situ process. The relationship may be assessed from a simulationmethod. The relationship may be stored on a database accessible by thecomputer system. The relationship may include one or more values of atleast one process characteristic and corresponding values of at leastone operating condition. Alternatively, the relationship may be ananalytical function.

[0772] In an embodiment, a desired process characteristic may be aselected composition of fluids produced from a formation. A selectedcomposition may correspond to a ratio of non-condensable hydrocarbons tocondensable hydrocarbons. In certain embodiments, increasing thepressure in the formation may increase the ratio of non-condensablehydrocarbons to condensable hydrocarbons of produced fluids. Thepressure in the formation may be controlled by increasing the pressureat a production well in an in situ process. In an alternate embodiment,another operating condition may be controlled simultaneously (e.g., theheat input rate).

[0773] In an embodiment, the pressure corresponding to the selectedcomposition may be assessed from two or more simulations at two or morepressures. In one embodiment, at least one of the pressures of thesimulations may be estimated from EQN. 9: $\begin{matrix}{p = \exp^{\lbrack{\frac{A}{T} + B}\rbrack}} & (9)\end{matrix}$

[0774] where p is measured in psia (pounds per square inch absolute), Tis measured in Kelvin, and A and B are parameters dependent on the valueof the desired process characteristic for a given type of formation.Values of A and B may be assessed from experimental data for a processcharacteristic in a given formation and may be used as input to EQN. 9.The pressure corresponding to the desired value of the processcharacteristic may then be estimated for use as input into a simulation.

[0775] The two or more simulations may provide a relationship betweenpressure and the composition of produced fluids. The pressurecorresponding to the desired composition may be interpolated from therelationship. A simulation at the interpolated pressure may be performedto assess a composition and one or more additional processcharacteristics. The accuracy of the interpolated pressure may beassessed by comparing the selected composition with the composition fromthe simulation. The pressure at the production well may be set to theinterpolated pressure to obtain produced fluids with the selectedcomposition.

[0776] In certain embodiments, the pressure of a formation may bereadily controlled at certain stages of an in situ process. At somestages of the in situ process, however, pressure control may berelatively difficult. For example, during a relatively short period oftime after heating has begun the permeability of the formation may berelatively low. At such early stages, the heat transfer front at whichpyrolysis occurs may be at a relatively large distance from a producerwell (i.e., the point at which pressure may be controlled). Therefore,there may be a significant pressure drop between the producer well andthe heat transfer front. Consequently, adjusting the pressure at aproducer well may have a relatively small influence on the pressure atwhich pyrolysis occurs at early stages of the in situ process. At laterstages of the in situ process when permeability has developed relativelyuniformly throughout the formation, the pressure of the producer wellcorresponds to the pressure in the formation. Therefore, the pressure atthe producer well may be used to control the pressure at which pyrolysisoccurs.

[0777] In some embodiments, a similar procedure may be followed toassess heater well pattern and producer well pattern characteristicsthat correspond to a desired process characteristic. For example, arelationship between the spacing of the heater wells and composition ofproduced fluids may be obtained from two or more simulations withdifferent heater well spacings.

[0778] FIGS. 226-237 depict results of simulations of in situ treatmentof tar sands formations. The simulations used EQN. 4 for modeling thepermeability of the tar sand formation. EQN. 5 was used for modeling thethermal conductivity. Chemical reactions in the formation were modeledwith EQNS. 7 and 8. The heat injection rate was calculated using CFX. Aconstant heat input rate of about 1640 Watts/m was imposed at the casinginterface. When the interface temperature reached about 760° C., theheat input rate was controlled to maintain the temperature of theinterface at about 760° C. The approximate heat input rate to maintainthe interface temperature at about 760° C. was used as input into STARS.STARS was then used to calculated the results in FIGS. 226-237.

[0779] The data from these simulations may be used to predict or assessoperating conditions and/or process characteristics for in situtreatment of tar sands formations. Similar simulations may be used topredict or assess operating conditions and/or process characteristicsfor treatment of other relatively permeable formations.

[0780] In one embodiment, a simulation method on a computer system maybe used in a method for modeling one or more stages of a process fortreating a relatively permeable formation in situ. The simulation methodmay be, for example, a reservoir simulation method. The simulationmethod may simulate heating of the formation, fluid flow, mass transfer,heat transfer, and chemical reactions in one or more of the stages ofthe process. In some embodiments, the simulation method may alsosimulate removal of contaminants from the formation, recovery of heatfrom the formation, and injection of fluids into the formation.

[0781] Method 9588 of modeling the one or more stages of a treatmentprocess is depicted in a flow chart in FIG. 30. The one or more stagesmay include heating stage 9574, pyrolyzation stage 9576, synthesis gasgeneration stage 9579, remediation stage 9582, and/or shut-in stage9585. The method may include providing at least one property 9572 of theformation to the computer system. In addition, operating conditions9573, 9577, 9580, 9583, and/or 9586 for one or more of the stages of thein situ process may be provided to the computer system. Operatingconditions may include, but not be limited to, pressure, temperature,heating rates, etc. In addition, operating conditions of a remediationstage may include a flow rate of ground water and injected water intothe formation, size of treatment area, and type of drive fluid.

[0782] In certain embodiments, the method may include assessing processcharacteristics 9575, 9578, 9581, 9584, and/or 9587 of the one or morestages using the simulation method. Process characteristics may includeproperties of a produced fluid such as API gravity and gas/oil ratio.Process characteristics may also include a pressure and temperature inthe formation, total mass recovery from the formation, and productionrate of fluid produced from the formation. In addition, a processcharacteristic of the remediation stage may include the type andconcentration of contaminants remaining in the formation.

[0783] In one embodiment, a simulation method may be used to assessoperating conditions of at least one of the stages of an in situ processthat results in desired process characteristics. FIG. 31 illustrates aflow chart of an embodiment of method 9701 for designing and controllingheating stage 9706, pyrolyzation stage 9708, synthesis gas generatingstage 9714, remediation stage 9720, and/or shut-in stage 9726 of an insitu process with a simulation method on a computer system. The methodmay include providing sets of operating conditions 9702, 9712, 9718,9724, and/or 9730 for at least one of the stages of the in situ process.In addition, desired process characteristics 9704, 9713, 9719, 9725,and/or 9731 for at least one of the stages of the in situ process mayalso be provided. The method may further include assessing at least oneadditional operating condition 9707, 9710, 9716, 9722, and/or 9728 forat least one of the stages that achieves the desired processcharacteristics of one or more stages.

[0784] In an embodiment, in situ treatment of a relatively permeableformation may substantially change physical and mechanical properties ofthe formation. The physical and mechanical properties may be affected bychemical properties of a formation, operating conditions, and processcharacteristics.

[0785] Changes in physical and mechanical properties due to treatment ofa formation may result in deformation of the formation. Deformationcharacteristics may include, but are not limited to, subsidence,compaction, heave, and shear deformation. Subsidence is a verticaldecrease in the surface of a formation over a treated portion of aformation. Heave is a vertical increase at the surface above a treatedportion of a formation. Surface displacement may result from severalconcurrent subsurface effects, such as the thermal expansion of layersof the formation, the compaction of the richest and weakest layers, andthe constraining force exerted by cooler rock that surrounds the treatedportion of the formation. In general, in the initial stages of heating aformation, the surface above the treated portion may show a heave due tothermal expansion of incompletely pyrolyzed formation material in thetreated portion of the formation. As a significant portion of formationbecomes pyrolyzed, the formation is weakened and pore pressure in thetreated portion declines. The pore pressure is the pressure of theliquid and gas that exists in the pores of a formation. The porepressure may be influenced by the thermal expansion of the organicmatter in the formation and the withdrawal of fluids from the formation.The decrease in the pore pressure tends to increase the effective stressin the treated portion. Since the pore pressure affects the effectivestress on the treated portion of a formation, pore pressure influencesthe extent of subsurface compaction in the formation. Compaction,another deformation characteristic, is a vertical decrease of asubsurface portion above or in the treated portion of the formation. Inaddition, shear deformation of layers both above and in the treatedportion of the formation may also occur. In some embodiments,deformation may adversely affect the in situ treatment process. Forexample, deformation may seriously damage surface facilities andwellbores.

[0786] In certain embodiments, an in situ treatment process may bedesigned and controlled such that the adverse influence of deformationis minimized or substantially eliminated. Computer simulation methodsmay be useful for design and control of an in situ process sincesimulation methods may predict deformation characteristics. For example,simulation methods may predict subsidence, compaction, heave, and sheardeformation in a formation from a model of an in situ process. Themodels may include physical, mechanical, and chemical properties of aformation. Simulation methods may be used to study the influence ofproperties of a formation, operating conditions, and processcharacteristics on deformation characteristics of the formation.

[0787]FIG. 32 illustrates model 9518 of a formation that may be used insimulations of deformation characteristics according to one embodiment.The formation model is a vertical cross-section that may include treatedportions 9524 with thickness 9532 and width or radius 9528. Treatedportion 9524 may include several layers or regions that vary in mineralcomposition and richness of organic matter. In one embodiment, treatedportion 9524 may be a dipping layer that is at an angle to the surfaceof the formation. The model may also include untreated portions such asoverburden 9521 and base rock 9526. Overburden 9521 may have thickness9530. Overburden 9521 may also include one or more portions, forexample, portion 9520 and portion 9522 that differ in composition. Forexample, portion 9522 may have a composition similar to treated portion9524 prior to treatment. Portion 9520 may be composed of organicmaterial, soil, rock, etc. Base rock 9526 may include barren rock withat least some organic material.

[0788] In some embodiments, an in situ process may be designed such thatit includes an untreated portion or strip between treated portions ofthe formation. FIG. 33 illustrates a schematic of a strip developmentaccording to one embodiment. The formation includes treated portion 9523and treated portion 9525 with thicknesses 9531 and widths 9533(thicknesses 9531 and widths 9533 may vary between portion 9523 andportion 9525). Untreated portion 9527 with width 9529 separates treatedportion 9523 from treated portion 9525. In some embodiments, width 9529is substantially less than widths 9533 since only smaller sections needto remain untreated to provide structural support. In some embodiments,the use of an untreated portion may decrease the amount of subsidence,heave, compaction, or shear deformation at and above the treatedportions of the formation.

[0789] In an embodiment, an in situ treatment process may be representedby a three-dimensional model. FIG. 34 depicts a schematic illustrationof a treated portion that may be modeled with a simulation. The treatedportion includes a well pattern with heat sources 9524 and producers9526. Dashed lines 9528 correspond to three planes of symmetry that maydivide the pattern into six equivalent sections. Solid lines betweenheat sources 9524 merely depict the pattern of heat sources (i.e., thesolid lines do not represent actual equipment between the heat sources).In some embodiments, a geomechanical model of the pattern may includeone of the six symmetry segments.

[0790]FIG. 35 depicts a horizontal cross section of a model of aformation for use by a simulation method according to one embodiment.The model includes grid elements 9530. Treated portion 9532 is locatedin the lower left corner of the model. Grid elements in the treatedportion may be sufficiently small to take into account the largevariations in conditions in the treated portion. In addition, distance9537 and distance 9539 may be sufficiently large such that thedeformation furthest from the treated portion is substantiallynegligible. Alternatively, a model may be approximated by a shape, suchas a cylinder. The diameter and height of the cylinder may correspond tothe size and height of the treated portion.

[0791] In certain embodiments, heat sources may be modeled by linesources that inject heat at a fixed rate. The heat sources may generatea reasonably accurate temperature distribution in the vicinity of theheat sources. Alternatively, a time-dependent temperature distributionmay be imposed as an average boundary condition.

[0792]FIG. 36 illustrates a flow chart of an embodiment of method 9532for modeling deformation due to treatment of a relatively permeableformation in situ. The method may include providing at least oneproperty 9534 of the formation to a computer system. The formation mayinclude a treated portion and an untreated portion. Properties mayinclude mechanical, chemical, thermal, and physical properties of theportions of the formation. For example, the mechanical properties mayinclude compressive strength, confining pressure, creep parameters,elastic modulus, Poisson's ratio, cohesion stress, friction angle, andcap eccentricity. Thermal and physical properties may include acoefficient of thermal expansion, volumetric heat capacity, and thermalconductivity. Properties may also include the porosity, permeability,saturation, compressibility, and density of the formation. Chemicalproperties may include, for example, the richness and/or organic contentof the portions of the formation.

[0793] In addition, at least one operating condition 9535 may beprovided to the computer system. For instance, operating conditions mayinclude, but are not limited to, pressure, temperature, process time,rate of pressure increase, heating rate, and characteristics of the wellpattern. In addition, an operating condition may include the overburdenthickness and thickness and width or radius of the treated portion ofthe formation. An operating condition may also include untreatedportions between treated portions of the formation, along with thehorizontal distance between treated portions of a formation.

[0794] In certain embodiments, the properties may include initialproperties of the formation. Furthermore, the model may includerelationships for the dependence of the mechanical, thermal, andphysical properties on conditions such as temperature, pressure, andrichness in the portions of the formation. For example, the compressivestrength in the treated portion of the formation may be a function ofrichness, temperature, and pressure. The volumetric heat capacity maydepend on the richness and the coefficient of thermal expansion may be afunction of the temperature and richness. Additionally, thepermeability, porosity, and density may be dependent upon the richnessof the formation.

[0795] In some embodiments, physical and mechanical properties for amodel of a formation may be assessed from samples extracted from ageological formation targeted for treatment. Properties of the samplesmay be measured at various temperatures and pressures. For example,mechanical properties may be measured using uniaxial, triaxial, andcreep experiments. In addition, chemical properties (e.g., richness) ofthe samples may also be measured. The dependence of properties ontemperature, pressure, and richness may then be assessed from themeasurements. In certain embodiments, the properties may be mapped on toa model using known sample locations.

[0796] In certain embodiments, assessing deformation using a simulationmethod may require a material or constitutive model. A constitutivemodel relates the stress in the formation to the strain or displacement.Mechanical properties may be entered into a suitable constitutive modelto calculate the deformation of the formation. In one embodiment, theDrucker-Prager-with-cap material model may be used to model thetime-independent deformation of the formation.

[0797] In an embodiment, the time-dependent creep or secondary creepstrain of the formation may also be modeled. For example, thetime-dependent creep in a formation may be modeled with a power law inEQN. 10:

ε=C×(σ₁−σ₃)^(D) ×t  (10)

[0798] where ε is the secondary creep strain, C is a creep multiplier,σ₁ is the axial stress, σ₃ is the confining pressure, D is a stressexponent, and t is the time. The values of C and D may be obtained fromfitting experimental data. In one embodiment, the creep rate may beexpressed by EQN. 11:

dε/dt=A×(σ₁/σ_(u))^(D)  (11)

[0799] where A is a multiplier obtained from fitting experimental dataand σ_(u) is the ultimate strength in uniaxial compression.

[0800] Additionally, the method shown in FIG. 36 may further includeassessing 9536 at least one process characteristic 9538 of the treatedportion of the formation. At least one process characteristic 9538 mayinclude a pore pressure distribution, a heat input rate, or a timedependent temperature distribution in the treated portion of theformation.

[0801] At least one process characteristic may be assessed by asimulation method. For example, a heat input rate may be estimated usinga body-fitted finite difference simulation package such as FLUENT.Similarly, the pore pressure distribution may be assessed from aspace-fitted or body-fitted simulation method such as STARS. In otherembodiments, the pore pressure may be assessed by a finite elementsimulation method such as ABAQUS. The finite element simulation methodmay employ line sinks of fluid to simulate the performance of productionwells.

[0802] Alternatively, process characteristics such as temperaturedistribution and pore pressure distribution may be approximated by othermeans. For example, the temperature distribution may be imposed as anaverage boundary condition in the calculation of deformationcharacteristics. The temperature distribution may be estimated fromresults of detailed calculations of a heating rate of a formation. Forexample, a treated portion may be heated to a pyrolyzation temperaturefor a specified period of time by heat sources and the temperaturedistribution assessed during heating of the treated portion. In anembodiment, the heat sources may be uniformly distributed and inject aconstant amount of heat. The temperature distribution inside most of thetreated portion may be substantially uniform during the specified periodof time. Some heat may be allowed to diffuse from the treated portioninto the overburden, base rock, and lateral rock. The treated portionmay be maintained at a selected temperature for a selected period oftime after the specified period of time by injecting heat from the heatsources as needed.

[0803] Similarly, the pore pressure distribution may also be imposed asan average boundary condition. The initial pore pressure distributionmay be assumed to be lithostatic. The pore pressure distribution maythen be gradually reduced to a selected pressure during the remainder ofthe simulation of the deformation characteristics.

[0804] In some embodiments, the method may include assessing at leastone deformation characteristic 9542 of the formation using simulationmethod 9540 on the computer system as a function of time. At least onedeformation characteristic may be assessed from at least one property9534, at least one process characteristic 9538, and at least oneoperating condition 9535. In certain embodiments, process characteristic9538 may be assessed by a simulation or process characteristic 9538 maybe measured. Deformation characteristics may include, but are notlimited to, subsidence, compaction, heave, and shear deformation in theformation.

[0805] Simulation method 9540 may be a finite element simulation methodfor calculating elastic, plastic, and time dependent behavior ofmaterials. For example, ABAQUS is a commercially available finiteelement simulation method from Hibbitt, Karlsson & Sorensen, Inc.located in Pawtucket, R.I. ABAQUS is capable of describing the elastic,plastic, and time dependent (creep) behavior of a broad class ofmaterials such as mineral matter, soils, and metals. In general, ABAQUSmay treat materials whose properties may be specified by user-definedconstitutive laws. ABAQUS may also calculate heat transfer and treat theeffect of pore pressure variations on rock deformation.

[0806] Computer simulations may be used to assess operating conditionsof an in situ process in a formation that may result in desireddeformation characteristics. FIG. 37 illustrates a flow chart of anembodiment of method 9544 for designing and controlling an in situprocess using a computer system. The method may include providing to thecomputer system at least one set of operating conditions 9546 for the insitu process. For instance, operating conditions may include pressure,temperature, process time, rate of pressure increase, heating rate,characteristics of the well pattern, the overburden thickness, thicknessand width of the treated portion of the formation and/or untreatedportions between treated portions of the formation, and the horizontaldistance between treated portions of a formation.

[0807] In addition, at least one desired deformation characteristic 9548for the in situ process may be provided to the computer system. Thedesired deformation characteristic may be a selected subsidence,selected heave, selected compaction, or selected shear deformation. Insome embodiments, at least one additional operating condition 9551 maybe assessed using simulation method 9550 that achieves at least onedesired deformation characteristic 9548. A desired deformationcharacteristic may be a value that does not adversely effect theoperation of an in situ process. For example, a minimum overburdennecessary to achieve a desired maximum value of subsidence may beassessed. In an embodiment, at least one additional operating condition9551 may be used to operate an in situ process 9552.

[0808] In one embodiment, operating conditions to obtain desireddeformation characteristics may be assessed from simulations of an insitu process based on multiple operating conditions. FIG. 38 illustratesa flow chart of an embodiment of method 9554 for assessing operatingconditions to obtain desired deformation characteristics. The method mayinclude providing one or more values of at least one operating condition9556 to a computer system for use as input to simulation method 9558.The simulation method may be a finite element simulation method forcalculating elastic, plastic, and creep behavior.

[0809] In some embodiments, the method may further include assessing oneor more values of deformation characteristics 9560 using simulationmethod 9558 based on the one or more values of at least one operatingcondition 9556. In one embodiment, a value of at least one deformationcharacteristic may include the deformation characteristic as a functionof time. A desired value of at least one deformation characteristic 9564for the in situ process may also be provided to the computer system. Anembodiment of the method may include assessing 9562 desired value of atleast one operating condition 9566 to achieve desired value of at leastone deformation characteristic 9564.

[0810] Desired value of at least one operating condition 9566 may beassessed from the values of at least one deformation characteristic 9560and the values of at least one operating condition 9556. For example,desired value 9566 may be obtained by interpolation of values 9560 andvalues 9556. In some embodiments, a value of at least one deformationcharacteristic may be assessed 9565 from the desired value of at leastone operating condition 9566 using simulation method 9558. In someembodiments, an operating condition to achieve a desired deformationcharacteristic may be assessed by comparing a deformation characteristicas a function of time for different operating conditions.

[0811] In an alternate embodiment, a desired value of at least oneoperating condition to achieve the desired value of at least onedeformation characteristic may be assessed using a relationship betweenat least one deformation characteristic and at least one operatingcondition of the in situ process. The relationship may be assessed usinga simulation method. Such relationship may be stored on a databaseaccessible by the computer system. The relationship may include one ormore values of at least one deformation characteristic and correspondingvalues of at least one operating condition. Alternatively, therelationship may be an analytical function.

[0812] Simulations have been used to investigate the effect of variousoperating conditions on the deformation characteristics of a formation.In one set of simulations, the formation was modeled as either acylinder or a rectangular slab. In the case of a cylinder, the model ofthe formation is described by a thickness of the treated portion, aradius, and a thickness of the overburden. The rectangular slab isdescribed by a width rather than a radius and by a thickness of thetreated section and overburden. FIG. 39 illustrates the influence ofoperating pressure on subsidence in a cylindrical model of a formationfrom a finite element simulation. The thickness of the treated portionis 189 m, the radius of the treated portion is 305 m, and the overburdenthickness is 201 m. FIG. 39 shows the vertical surface displacement inmeters over a period of years. Curve 9568 corresponds to an operatingpressure of 27.6 bars absolute and curve 9569 to an operating pressureof 6.9 bars absolute. It is to be understood that the surfacedisplacements set forth in FIG. 39 are only illustrative (actual surfacedisplacements will generally differ from those shown in FIG. 39). FIG.39 demonstrates, however, that increasing the operating pressure maysubstantially reduce subsidence.

[0813]FIGS. 40 and 41 illustrate the influence of the use of anuntreated portion between two treated portions. FIG. 40 is thesubsidence in a rectangular slab model with a treated portion thicknessof 189 m, treated portion width of 649 m, and overburden thickness of201 m. FIG. 41 represents the subsidence in a rectangular slab modelwith two treated portions separated by an untreated portion, as picturedin FIG. 33. The thickness of the treated portion and the overburden arethe same as the model corresponding to FIG. 40. The width of eachtreated portion is one half of the width of the treated portion of themodel in FIG. 40. Therefore, the total width of the treated portions isthe same for each model. The operating pressure in each case is 6.9 barsabsolute. As with FIG. 39, the surface displacements in FIGS. 40 and 41are only illustrative. A comparison of FIGS. 40 and 41, however, showsthat the use of an untreated portion reduces the subsidence by about25%. In addition, the initial heave is also reduced.

[0814] In certain embodiments, a computer system may be used to operatean in situ process for treating a relatively permeable formation. The insitu process may include providing heat from one or more heat sources toat least one portion of the formation. In addition, the in situ processmay also include allowing the heat to transfer from the one or more heatsources to a selected section of the formation. FIG. 42 illustratesmethod 9480 for operating an in situ process using a computer system.The method may include operating in situ process 9482 using one or moreoperating parameters. Operating parameters may include properties of theformation, such as heat capacity, density, permeability, thermalconductivity, porosity, and/or chemical reaction data. In addition,operating parameters may include operating conditions. Operatingconditions may include, but are not limited to, thickness and area ofheated portion of the formation, pressure, temperature, heating rate,heat input rate, process time, production rate, time to obtain a givenproduction rate, weight percentage of gases, and/or peripheral waterrecovery or injection. Operating conditions may also includecharacteristics of the well pattern such as producer well location,producer well orientation, ratio of producer wells to heater wells,heater well spacing, type of heater well pattern, heater wellorientation, and/or distance between an overburden and horizontal heaterwells. Operating parameters may also include mechanical properties ofthe formation. Operating parameters may include deformationcharacteristics, such as fracture, strain, subsidence, heave,compaction, and/or shear deformation.

[0815] In certain embodiments, at least one operating parameter 9484 ofin situ process 9482 may be provided to computer system 9486. Computersystem 9486 may be at or near in situ process 9482. Alternatively,computer system 9486 may be at a location remote from in situ process9482. The computer system may include a first simulation method forsimulating a model of in situ process 9482. In one embodiment, the firstsimulation method may include method 9470 illustrated in FIG. 21, method9360 illustrated in FIG. 23, method 8630 illustrated in FIG. 25, method9390 illustrated in FIG. 26, method 9405 illustrated in FIG. 27, method9430 illustrated in FIG. 28, and/or method 9450 illustrated in FIG. 29.The first simulation method may include a body-fitted finite differencesimulation method such as FLUENT or space-fitted finite differencesimulation method such as STARS. The first simulation method may performa reservoir simulation. A reservoir simulation method may be used todetermine operating parameters including, but not limited to, pressure,temperature, heating rate, heat input rate, process time, productionrate, time to obtain a given production rate, weight percentage ofgases, and peripheral water recovery or injection.

[0816] In an embodiment, the first simulation method may also calculatedeformation in a formation. A simulation method for calculatingdeformation characteristics may include a finite element simulationmethod such as ABAQUS. The first simulation method may calculatefracture progression, strain, subsidence, heave, compaction, and sheardeformation. A simulation method used for calculating deformationcharacteristics may include method 9532 illustrated in FIG. 36 and/ormethod 9554 illustrated in FIG. 38.

[0817] The method may further include using at least one parameter 9484with a first simulation method and the computer system to provideassessed information 9488 about in situ process 9482. Operatingparameters from the simulation may be compared to operating parametersof in situ process 9482. Assessed information from a simulation mayinclude a simulated relationship between one or more operatingparameters with at least one parameter 9484. For example, the assessedinformation may include a relationship between operating parameters suchas pressure, temperature, heating input rate, or heating rate andoperating parameters relating to product quality.

[0818] In some embodiments, assessed information may includeinconsistencies between operating parameters from simulation andoperating parameters from in situ process 9482. For example, thetemperature, pressure, product quality, or production rate from thefirst simulation method may differ from in situ process 9482. The sourceof the inconsistencies may be assessed from the operating parametersprovided by simulation. The source of the inconsistencies may includedifferences between certain properties used in a simulated model of insitu process 9482 and in situ process 9482. Certain properties mayinclude, but are not limited to, thermal conductivity, heat capacity,density, permeability, or chemical reaction data. Certain properties mayalso include mechanical properties such as compressive strength,confining pressure, creep parameters, elastic modulus, Poisson's ratio,cohesion stress, friction angle, and cap eccentricity.

[0819] In one embodiment, assessed information may include adjustmentsin one or more operating parameters of in situ process 9482. Theadjustments may compensate for inconsistencies between simulatedoperating parameters and operating parameters from in situ process 9482.Adjustments may be assessed from a simulated relationship between atleast one parameter 9484 and one or more operating parameters.

[0820] For example, an in situ process may have a particular hydrocarbonfluid production rate, e.g., 1 m³/day, after a particular period of time(e.g., 90 days). A theoretical temperature at an observation well (e.g.,100° C.) may be calculated using given properties of the formation.However, a measured temperature at an observation well (e.g., 80° C.)may be lower than the theoretical temperature. A simulation on acomputer system may be performed using the measured temperature. Thesimulation may provide operating parameters of the in situ process thatcorrespond to the measured temperature. The operating parameters fromsimulation may be used to assess a relationship between, for example,temperature or heat input rate and the production rate of the in situprocess. The relationship may indicate that the heat capacity or thermalconductivity of the formation used in the simulation is inconsistentwith the formation.

[0821] In some embodiments, the method may further include usingassessed information 9488 to operate in situ process 9482. As usedherein, “operate” refers to controlling or changing operating conditionsof an in situ process. For example, the assessed information mayindicate that the thermal conductivity of the formation in the aboveexample is lower than the thermal conductivity used in the simulation.Therefore, the heat input rate to in situ process 9482 may be increasedto operate at the theoretical temperature.

[0822] In other embodiments, the method may include obtaining 9492information 9494 from a second simulation method and the computer systemusing assessed information 9488 and desired parameter 9490. In oneembodiment, the first simulation method may be the same as the secondsimulation method. In another embodiment, the first and secondsimulation methods may be different. Simulations may provide arelationship between at least one operating parameter and at least oneother parameter. Additionally, obtained information 9494 may be used tooperate in situ process 9482.

[0823] Obtained information 9494 may include at least one operatingparameter for use in the in situ process that achieves the desiredparameter. In one embodiment, simulation method 9450 illustrated in FIG.29 may be used to obtain at least one operating parameter that achievesthe desired parameter. For example, a desired hydrocarbon fluidproduction rate for an in situ process may be 6 m³/day. One or moresimulations may be used to determine the operating parameters necessaryto achieve a hydrocarbon fluid production rate of 6 m³/day. In someembodiments, model parameters used by simulation method 9450 may becalibrated to account for differences observed between simulations andin situ process 9482. In one embodiment, simulation method 9390illustrated in FIG. 26 may be used to calibrate model parameters. Inanother embodiment, simulation method 9554 illustrated in FIG. 38 may beused to obtain at least one operating parameter that achieves a desireddeformation characteristic.

[0824]FIG. 43 illustrates a schematic of an embodiment for controllingin situ process 9701 in a formation using a computer simulation method.In situ process 9701 may include sensor 9702 for monitoring operatingparameters. Sensor 9702 may be located in a barrier well, a monitoringwell, a production well, or a heater well. Sensor 9702 may monitoroperating parameters such as subsurface and surface conditions in theformation. Subsurface conditions may include pressure, temperature,product quality, and deformation characteristics, such as fractureprogression. Sensor 9702 may also monitor surface data such as pumpstatus (i.e., on or off), fluid flow rate, surface pressure/temperature,and heater power. The surface data may be monitored with instrumentsplaced at a well.

[0825] In addition, at least one operating parameter 9704 measured bysensor 9702 may be provided to local computer system 9708.Alternatively, operating parameter 9704 may be provided to remotecomputer system 9706. Computer system 9706 may be, for example, apersonal desktop computer system, a laptop, or personal digitalassistant such as a palm pilot. FIG. 44 illustrates several ways thatinformation such as operating parameter 9704 may be transmitted from insitu process 9701 to remote computer system 9706. Information may betransmitted by means of internet 9718, hardwire telephone lines 9720,and wireless communications 9722. Wireless communications 9722 mayinclude transmission via satellite 9724.

[0826] In some embodiments, operating parameter 9704 may be provided tocomputer system 9708 or 9706 automatically during the treatment of aformation. Computer systems 9706 and 9708 may include a simulationmethod for simulating a model of the in situ treatment process 9701. Thesimulation method may be used to obtain information 9710 about the insitu process.

[0827] In an embodiment, a simulation of in situ process 9701 may beperformed manually at a desired time. Alternatively, a simulation may beperformed automatically when a desired condition is met. For instance, asimulation may be performed when one or more operating parameters reach,or fail to reach, a particular value at a particular time. For example,a simulation may be performed when the production rate fails to reach aparticular value at a particular time.

[0828] In some embodiments, information 9710 relating to in situ process9701 may be provided automatically by computer system 9706 or 9708 foruse in controlling in situ process 9701. Information 9710 may includeinstructions relating to control of in situ process 9701. Information9710 may be transmitted from computer system 9706 via internet,hardwire, wireless, or satellite transmission as illustrated in FIG. 44.Information 9710 may be provided to computer system 9712. Computersystem 9712 may also be at a location remote from the in situ process.Computer system 9712 may process information 9710 for use in controllingin situ process 9701. For example, computer system 9712 may useinformation 9710 to determine adjustments in one or more operatingparameters. Computer system 9712 may then automatically adjust 9716 oneor more operating parameters of in situ process 9701. Alternatively, oneor more operating parameters of in situ process 9701 may be displayedand then, optionally, adjusted manually 9714.

[0829]FIG. 45 illustrates a schematic of an embodiment for controllingin situ process 9701 in a formation using information 9710. Information9710 may be obtained using a simulation method and a computer system.Information 9710 may be provided to computer system 9712. Information9710 may include information that relates to adjusting one or moreoperating parameters. Output 9713 from computer system 9712 may beprovided to display 9722, data storage 9724, or surface facility 9723.Output 9713 may also be used to automatically control conditions in theformation by adjusting one or more operating parameters. Output 9713 mayinclude instructions to adjust pump status and flow rate at a barrierwell 9726, adjust pump status and flow rate at a production well 9728,and/or adjust the heater power at a heater well 9730. Output 9713 mayalso include instructions to heating pattern 9732 of in situ process9701. For example, an instruction may be to add one or more heater wellsat particular locations. In addition, output 9713 may includeinstructions to shut-in the formation 9734.

[0830] Alternatively, output 9713 may be viewed by operators of the insitu process on display 9722. The operators may then use output 9713 tomanually adjust one or more operating parameters.

[0831]FIG. 46 illustrates a schematic of an embodiment for controllingin situ process 9701 in a formation using a simulation method and acomputer system. At least one operating parameter 9704 from in situprocess 9701 may be provided to computer system 9736. Computer system9736 may include a simulation method for simulating a model of in situprocess 9701. Computer system 9736 may use the simulation method toobtain information 9738 about in situ process 9701. Information 9738 maybe provided to data storage 9740, display 9742, and analysis 9743. In anembodiment, information 9738 may be automatically provided to in situprocess 9701. Information 9738 may then be used to operate in situprocess 9701.

[0832] Analysis 9743 may include review of information 9738 and/or useof information 9738 to operate in situ process 9701. Analysis 9743 mayinclude obtaining additional information 9750 using one or moresimulations 9746 of in situ process 9701. One or more simulations may beused to obtain additional or modified model parameters of in situprocess 9701. The additional or modified model parameters may be used tofurther assess in situ process 9701. Simulation method 9390 illustratedin FIG. 26 may be used to determine additional or modified modelparameters. Method 9390 may use at least one operating parameter 9704and information 9738 to calibrate model parameters. For example, atleast one operating parameter 9704 may be compared to at least onesimulated operating parameter. Model parameters may be modified suchthat at least one simulated operating parameter matches or approximatesat least one operating parameter 9704.

[0833] In an embodiment, analysis 9743 may include obtaining 9744additional information 9748 about properties of in situ process 9701.Properties may include, for example, thermal conductivity, heatcapacity, porosity, or permeability of one or more portions of theformation. Properties may also include chemical reaction data such as,chemical reactions, chemical components, and chemical reactionparameters. Properties may be obtained from the literature or from fieldor laboratory experiments. For example, properties of core samples ofthe treated formation may be measured in a laboratory. Additionalinformation 9748 may be used to operate in situ process 9701.Alternatively, additional information 9743 may be used in one or moresimulations 9746 to obtain additional information 9750. For example,additional information 9750 may include one or more operating parametersthat may be used to operate in situ process 9701 with a desiredoperating parameter. In one embodiment, method 9450 illustrated in FIG.29 may be used to determine operating parameters to achieve a desiredparameter. The operating parameters may then be used to operate in situprocess 9701.

[0834] An in situ process for treating a formation may include treatinga selected section of the formation with a minimum average overburdenthickness. The minimum average overburden thickness may depend on a typeof hydrocarbon resource and geological formation surrounding thehydrocarbon resource. An overburden may, in some embodiments, besubstantially impermeable so that fluids produced in the selectedsection are inhibited from passing to the ground surface through theoverburden. A minimum overburden thickness may be determined as theminimum overburden needed to inhibit the escape of fluids produced inthe formation and to inhibit breakthrough to the surface due toincreased pressure within the formation during in the situ conversionprocess. Determining this minimum overburden thickness may be dependenton, for example, composition of the overburden, maximum pressure to bereached in the formation during the in situ conversion process,permeability of the overburden, composition of fluids produced in theformation, and/or temperatures in the formation or overburden. A ratioof overburden thickness to hydrocarbon resource thickness may be usedduring selection of resources to produce using an in situ thermalconversion process.

[0835] Selected factors may be used to determine a minimum overburdenthickness. These selected factors may include overall thickness of theoverburden, lithology and/or rock properties of the overburden, earthstresses, expected extent of subsidence and/or reservoir compaction, apressure of a process to be used in the formation, and extent andconnectivity of natural fracture systems surrounding the formation.

[0836]FIG. 47 illustrates a flow chart of a computer-implemented methodfor determining a selected overburden thickness. Selected sectionproperties 6366 may be input into computational system 6250. Propertiesof the selected section may include type of formation, density,permeability, porosity, earth stresses, etc. Selected section properties6366 may be used by a software executable to determine minimumoverburden thickness 6368 for the selected section. The softwareexecutable may be, for example, ABAQUS. The software executable mayincorporate selected factors. Computational system 6250 may also run asimulation to determine minimum overburden thickness 6368. The minimumoverburden thickness may be determined so that fractures that allowformation fluid to pass to the ground surface will not form within theoverburden during an in situ process. A formation may be selected fortreatment by computational system 6250 based on properties of theformation and/or properties of the overburden as determined herein.Overburden properties 6364 may also be input into computational system6250. Properties of the overburden may include a type of material in theoverburden, density of the overburden, permeability of the overburden,earth stresses, etc. Computational system 6250 may also be used todetermine operating conditions and/or control operating conditions foran in situ process of treating a formation.

[0837] Heating of the formation may be monitored during an in situconversion process. Monitoring heating of a selected section may includecontinuously monitoring acoustical data associated with the selectedsection. Acoustical data may include seismic data or any acoustical datathat may be measured, for example, using geophones, hydrophones, orother acoustical sensors. In an embodiment, a continuous acousticalmonitoring system can be used to monitor (e.g., intermittently orconstantly) the formation. The formation can be monitored (e.g., usinggeophones at 2 kilohertz, recording measurements every ⅛ of amillisecond) for undesirable formation conditions. In an embodiment, acontinuous acoustical monitoring system may be obtained from OyoInstruments (Houston, Tex.).

[0838] Acoustical data may be acquired by recording information usingunderground acoustical sensors located within and/or proximate a treatedformation area. Acoustical data may be used to determine a type and/orlocation of fractures developing within the selected section. Acousticaldata may be input into a computational system to determine the typeand/or location of fractures. Also, heating profiles of the formation orselected section may be determined by the computational system using theacoustical data. The computational system may run a software executableto process the acoustical data. The computational system may be used todetermine a set of operating conditions for treating the formation insitu. The computational system may also be used to control the set ofoperating conditions for treating the formation in situ based on theacoustical data. Other properties, such as a temperature of theformation, may also be input into the computational system.

[0839] An in situ conversion process may be controlled by using some ofthe production wells as injection wells for injection of steam and/orother process modifying fluids (e.g., hydrogen, which may affect aproduct composition through in situ hydrogenation).

[0840] In certain embodiments, it may be possible to use welltechnologies that may operate at high temperatures. These technologiesmay include both sensors and control mechanisms. The heat injectionprofiles and hydrocarbon vapor production may be adjusted on a morediscrete basis. It may be possible to adjust heat profiles andproduction on a bed-by-bed basis or in meter-by-meter increments. Thismay allow the ICP to compensate, for example, for different thermalproperties and/or organic contents in an interbedded lithology. Thus,cold and hot spots may be inhibited from forming, the formation may notbe overpressurized, and/or the integrity of the formation may not behighly stressed, which could cause deformations and/or damage towellbore integrity.

[0841]FIGS. 48 and 49 illustrate schematic diagrams of a plan view and across-sectional representation, respectively, of a zone being treatedusing an in situ conversion process (ICP). The ICP may causemicroseismic failures, or fractures, within the treatment zone fromwhich a seismic wave may be emitted. Treatment zone 6400 may be heatedusing heat provided from heater 6410 placed in heater well 6402.Pressure in treatment zone 6400 may be controlled by producing someformation fluid through heater wells 6402 and/or production wells. Heatfrom heater 6410 may cause failure 6406 in a portion of the formationproximate treatment zone 6400. Failure 6406 may be a localized rockfailure within a rock volume of the formation. Failure 6406 may be aninstantaneous failure. Failure 6406 tends to produce seismic disturbance6408. Seismic disturbance 6408 may be an elastic or microseismicdisturbance that propagates as a body wave in the formation surroundingthe failure. Magnitude and direction of seismic disturbance as measuredby sensors may indicate a type of macro-scale failure that occurs withinthe formation and/or treatment zone 6400. For example, seismicdisturbance 6408 may be evaluated to indicate a location, orientation,and/or extent of one or more macro-scale failures that occurred in theformation due to heat treatment of the treatment zone 6400.

[0842] Seismic disturbance 6408 from one or more failures 6406 may bedetected with one or more sensors 6412. Sensor 6412 may be a geophone,hydrophone, accelerometer, and/or other seismic sensing device. Sensors6412 may be placed in monitoring well 6404 or monitoring wells.Monitoring wells 6404 may be placed in the formation proximate heaterwell 6402 and treatment zone 6400. In certain embodiments, threemonitoring wells 6404 are placed in the formation such that a locationof failure 6406 may be triangulated using sensors 6412 in eachmonitoring well.

[0843] In an in situ conversion process embodiment, sensors 6412 maymeasure a signal of seismic disturbance 6408. The signal may include awave or set of waves emitted from failure 6406. The signals may be usedto determine an approximate location of failure 6406. An approximatetime at which failure 6406 occurred, causing seismic disturbance 6408,may also be determined from the signal. This approximate location andapproximate time of failure 6406 may be used to determine if failure6406 can propagate into an undesired zone of the formation. Theundesired zone may include a water aquifer, a zone of the formationundesired for treatment, overburden 540 of the formation, and/orunderburden 6416 of the formation. An aquifer may also lie aboveoverburden 540 or below underburden 6416. Overburden 540 and/orunderburden 6416 may include one or more rock layers that can befractured and allow formation fluid to undesirably escape from the insitu conversion process. Sensors 6412 may be used to monitor aprogression of failure 6406 (i.e., an increase in extent of the failure)over a period of time.

[0844] In certain embodiments, a location of failure 6406 may be moreprecisely determined using a vertical distribution of sensors 6412 alongeach monitoring well 6404. The vertical distribution of sensors 6412 mayalso include at least one sensor above overburden 540 and/or belowunderburden 6416. The sensors above overburden 540 and/or belowunderburden 6416 may be used to monitor penetration (or an absence ofpenetration) of a failure through the overburden or underburden.

[0845] If failure 6406 may propagate into an undesired zone of theformation, a parameter for treatment of treatment zone 6400 controlledthrough heater well 6402 may be altered to inhibit propagation of thefailure. The parameter of treatment may include a pressure in treatmentzone 6400, a volume (or flow rate) of fluids injected into the treatmentzone or removed from the treatment zone, or a heat input rate fromheater 6410 into the treatment zone.

[0846]FIG. 50 illustrates a flow chart of an embodiment of a method usedto monitor treatment of a formation. Treatment plan 6420 may be providedfor a treatment zone (e.g., treatment zone 6400 in FIGS. 48 and 49).Parameters 6422 for treatment plan 6420 may include, but are not limitedto, pressure in the treatment zone, heating rate of the treatment zone,and average temperature in the treatment zone. Treatment parameters 6422may be controlled to treat through heat sources, production wells,and/or injection wells. A failure or failures may occur during treatmentof the treatment zone for a given set of parameters. Seismicdisturbances that indicate a failure may be detected by sensors placedin one or more monitoring wells in monitoring step 6424. The seismicdisturbances may be used to determine a location, a time, and/or extentof the one or more failures in determination step 6426. Determinationstep 6426 may include imaging the seismic disturbances to determine aspatial location of a failure or failures and/or a time at which thefailure or failures occurred. The location, time, and/or extent of thefailure or failures may be processed to determine if treatmentparameters 6422 may be altered to inhibit the propagation of a failureor failures into an undesired zone of the formation in interpretationstep 6428.

[0847] In an in situ conversion process embodiment, a recording systemmay be used to continuously monitor signals from sensors placed in aformation. The recording system may continuously record the signals fromsensors. The recording system may save the signals as data. The data maybe permanently saved by the recording system. The recording system maysimultaneously monitor signals from sensors. The signals may bemonitored at a selected sampling rate (e.g., about once every 0.25milliseconds). In some embodiments, two recording systems may be used tocontinuously monitor signals from sensors. A recording system may beused to record each signal from the sensors at the selected samplingrate for a desired time period. A controller may be used when therecording system is used to monitor a signal. The controller may be acomputational system or computer. In an embodiment using two or morerecording systems, the controller may direct which recording system isused for a selected time period. The controller may include a globalpositioning satellite (GPS) clock. The GPS clock may be used to providea specific time for a recording system to begin monitoring signals(e.g., a trigger time) and a time period for the monitoring of signals.The controller may provide the specific time for the recording system tobegin monitoring signals to a trigger box. The trigger box may be usedto supply a trigger pulse to a recording system to begin monitoringsignals.

[0848] A storage device may be used to record signals monitored by arecording system. The storage device may include a tape drive (e.g., ahigh-speed high-capacity tape drive) or any device capable of recordingrelatively large amounts of data at very short time intervals. In anembodiment using two recording systems, the storage device may receivedata from the first recording system while the second recording systemis monitoring signals from one or more sensors, or vice versa. Thisenables continuous data coverage so that all or substantially allmicroseismic events that occur will be detected. In some embodiments,heat progress through the formation may be monitored by measuringmicroseismic events caused by heating of various portions of theformation.

[0849] In some embodiments, monitoring heating of a selected section ofthe formation may include electromagnetic monitoring of the selectedsection. Electromagnetic monitoring may include measuring a resistivitybetween at least two electrodes within the selected section. Data fromelectromagnetic monitoring may be input into a computational system andprocessed as described above.

[0850] A relationship between a change in characteristics of formationfluids with temperature in an in situ conversion process may bedeveloped. The relationship may relate the change in characteristicswith temperature to a heating rate and temperature for the formation.The relationship may be used to select a temperature which can be usedin an isothermal experiment to determine a quantity and quality of aproduct produced by ICP in a formation without having to use one or moreslow heating rate experiments. The isothermal experiment may beconducted in a laboratory or similar test facility. The isothermalexperiment may be conducted much more quickly than experiments thatslowly increase temperatures. An appropriate selection of a temperaturefor an isothermal experiment may be significant for prediction ofcharacteristics of formation fluids. The experiment may includeconducting an experiment on a sample of a formation. The experiment mayinclude producing hydrocarbons from the sample.

[0851] For example, first order kinetics may be generally assumed for areaction producing a product. Assuming first order kinetics and a linearheating rate, the change in concentration (a characteristic of aformation fluid being the concentration of a component) with temperaturemay be defined by the equation:

dC/dT=−(k ₀ /m)×e ^((−E/RT)) C;  (12)

[0852] in which C is the concentration of a component, T is temperaturein Kelvin, k₀ is the frequency factor of the reaction, m is the heatingrate, E is the activation energy, and R is the gas constant.

[0853] EQN. 12 may be solved for a concentration at a selectedtemperature based on an initial concentration at a first temperature.The result is the equation: $\begin{matrix}{{C = {C_{0} \times ^{\frac{k_{0}{RT}^{2}^{- \frac{E}{RT}}}{m\quad E}}}};} & (13)\end{matrix}$

[0854] in which C is the concentration of a component at temperature Tand C₀ is an initial concentration of the component.

[0855] Substituting EQN. 13 into EQN. 12 yields the expression:$\begin{matrix}{{\frac{C}{T} = {{- \frac{k_{0}C_{0}}{m}} \times ^{({{- \frac{E}{RT}} - {\frac{k_{0}{RT}^{2}}{m\quad E} \times ^{- \frac{E}{RT}}}})}}};} & (14)\end{matrix}$

[0856] which relates the change in concentration C with temperature Tfor first-order kinetics and a linear heating rate.

[0857] Typically, in application of an ICP to a relatively permeableformation, the heating rate may not be linear due to temperaturelimitations in heat sources and/or in heater wells. For example, heatingmay be reduced at higher temperatures so that a temperature in a heaterwell is maintained below a desired temperature (e.g., about 650° C).This may provide a non-linear heating rate that is relatively slowerthan a linear heating rate. The non-linear heating rate may be expressedas:

T=m×t ^(n);  (15)

[0858] in which t is time and n is an exponential decay term for theheating rate, and in which n is typically less than 1 (e.g., about0.75).

[0859] Using EQN. 15 in a first-order kinetics equation gives theexpression: $\begin{matrix}{{C = {C_{0} \times ^{({{- \frac{k_{0}{RT}^{\frac{n + 1}{n}}}{m^{1/n}n}} \times ^{\frac{- E}{RT}}})}}};} & (16)\end{matrix}$

[0860] which is a generalization of EQN. 13 for a non-linear heatingrate.

[0861] An isothermal experiment may be conducted at a selectedtemperature to determine a quality and a quantity of a product producedusing an ICP in a formation. The selected temperature may be atemperature at which half the initial concentration, C₀, has beenconverted into product (i.e., C/C₀=½). EQN. 16 may be solved for thisvalue, giving the expression. $\begin{matrix}{{{{\ln \quad \left( \frac{k_{0}R}{m^{1/n}n} \right)} - {\ln \quad \left( {\ln \quad 2} \right)}} = {\frac{E}{{RT}_{1/2}} - {\frac{n + 1}{n} \times \ln \quad T_{1/2}}}};} & (17)\end{matrix}$

[0862] in which T_(1/2) is the selected temperature which corresponds toconverting half of the initial concentration into product.Alternatively, an equation such as EQN. 14 may be used with a heatingrate that approximates a heating rate expected in a temperature rangewherein situ conversion of hydrocarbons is expected. EQN. 17 may be usedto determine a selected temperature based on a heating rate that may beexpected for ICP in at least a portion of a formation. The heating ratemay be selected based on parameters such as, but not limited to, heaterwell spacing, heater well installation economics (e.g., drilling costs,heater costs, etc.), and maximum heater output. At least one property ofthe formation may also be used to determine the heating rate. At leastone property may include, but is not limited to, a type of formation,formation heat capacity, formation depth, permeability, thermalconductivity, and total organic content. The selected temperature may beused in an isothermal experiment to determine product quality and/orquantity. The product quality and/or quantity may also be determined ata selected pressure in the isothermal experiment. The selected pressuremay be a pressure used for an ICP. The selected pressure may be adjustedto produce a desired product quality and/or quantity in the isothermalexperiment. The adjusted selected pressure may be used in an ICP toproduce the desired product quality and/or quality from the formation.

[0863] In some embodiments, EQN. 17 may be used to determine a heatingrate (m or m^(n)) used in an ICP based on results from an isothermalexperiment at a selected temperature (T_(1/2)). For example, isothermalexperiments may be performed at a variety of temperatures. The selectedtemperature may be chosen as a temperature at which a product of desiredquality and/or quantity is produced. The selected temperature may beused in EQN. 17 to determine the desired heating rate during ICP toproduce a product of the desired quality and/or quantity.

[0864] Alternatively, if a heating rate is estimated, at least in afirst instance, by optimizing costs and incomes such as heater wellcosts and the time required to produce hydrocarbons, then constants foran equation such as EQN. 17 may be determined by data from an experimentwhen the temperature is raised at a constant rate. With the constants ofEQN. 17 estimated and heating rates estimated, a temperature forisothermal experiments may be calculated. Isothermal experiments may beperformed much more quickly than experiments at anticipated heatingrates (i.e., relatively slow heating rates). Thus, the effect ofvariables (such as pressure) and the effect of applying additional gases(such as, for example, steam and hydrogen) may be determined byrelatively fast experiments.

[0865] In an embodiment, a relatively permeable formation may be heatedwith a natural distributed combustor system located in the formation.The generated heat may be allowed to transfer to a selected section ofthe formation. A natural distributed combustor may oxidize hydrocarbonsin a formation in the vicinity of a wellbore to provide heat to aselected section of the formation.

[0866] A temperature sufficient to support oxidation may be at leastabout 200° C. or 250° C. The temperature sufficient to support oxidationwill tend to vary depending on many factors (e.g., a composition of thehydrocarbons in the relatively permeable formation, water content of theformation, and/or type and amount of oxidant). Some water may be removedfrom the formation prior to heating. For example, the water may bepumped from the formation by dewatering wells. The heated portion of theformation may be near or substantially adjacent to an opening in therelatively permeable formation. The opening in the formation may be aheater well formed in the formation. The heated portion of therelatively permeable formation may extend radially from the opening to awidth of about 0.3 m to about 1.2 m. The width, however, may also beless than about 0.9 m. A width of the heated portion may vary with time.In certain embodiments, the variance depends on factors including awidth of formation necessary to generate sufficient heat duringoxidation of carbon to maintain the oxidation reaction without providingheat from an additional heat source.

[0867] After the portion of the formation reaches a temperaturesufficient to support oxidation, an oxidizing fluid may be provided intothe opening to oxidize at least a portion of the hydrocarbons at areaction zone or a heat source zone within the formation. Oxidation ofthe hydrocarbons will generate heat at the reaction zone. The generatedheat will in most embodiments transfer from the reaction zone to apyrolysis zone in the formation. In certain embodiments, the generatedheat transfers at a rate between about 650 watts per meter and 1650watts per meter as measured along a depth of the reaction zone. Uponoxidation of at least some of the hydrocarbons in the formation, energysupplied to the heater for initially heating the formation to thetemperature sufficient to support oxidation may be reduced or turnedoff. Energy input costs may be significantly reduced using naturaldistributed combustors, thereby providing a significantly more efficientsystem for heating the formation.

[0868] In an embodiment, a conduit may be disposed in the opening toprovide oxidizing fluid into the opening. The conduit may have floworifices or other flow control mechanisms (i.e., slits, venturi meters,valves, etc.) to allow the oxidizing fluid to enter the opening. Theterm “orifices” includes openings having a wide variety ofcross-sectional shapes including, but not limited to, circles, ovals,squares, rectangles, triangles, slits, or other regular or irregularshapes. The flow orifices may be critical flow orifices in someembodiments. The flow orifices may provide a substantially constant flowof oxidizing fluid into the opening, regardless of the pressure in theopening.

[0869] In some embodiments, the number of flow orifices may be limitedby the diameter of the orifices and a desired spacing between orificesfor a length of the conduit. For example, as the diameter of theorifices decreases, the number of flow orifices may increase, and viceversa. In addition, as the desired spacing increases, the number of floworifices may decrease, and vice versa. The diameter of the orifices maybe determined by a pressure in the conduit and/or a desired flow ratethrough the orifices. For example, for a flow rate of about 1.7 standardcubic meters per minute and a pressure of about 7 bars absolute, anorifice diameter may be about 1.3 mm with a spacing between orifices ofabout 2 m. Smaller diameter orifices may plug more readily than largerdiameter orifices. Orifices may plug for a variety of reasons. Thereasons may include, but are not limited to, contaminants in the fluidflowing in the conduit and/or solid deposition within or proximate theorifices.

[0870] In some embodiments, the number and diameter of the orifices arechosen such that a more even or nearly uniform heating profile will beobtained along a depth of the opening in the formation. A depth of aheated formation that is intended to have an approximately uniformheating profile may be greater than about 300 m, or even greater thanabout 600 m. Such a depth may vary, however, depending on, for example,a type of formation to be heated and/or a desired production rate.

[0871] In some embodiments, flow orifices may be disposed in a helicalpattern around the conduit within the opening. The flow orifices may bespaced by about 0.3 m to about 3 m between orifices in the helicalpattern. In some embodiments, the spacing may be about 1 m to about 2 mor, for example, about 1.5 m.

[0872] The flow of oxidizing fluid into the opening may be controlledsuch that a rate of oxidation at the reaction zone is controlled.Transfer of heat between incoming oxidant and outgoing oxidationproducts may heat the oxidizing fluid. The transfer of heat may alsomaintain the conduit below a maximum operating temperature of theconduit.

[0873]FIG. 51 illustrates an embodiment of a natural distributedcombustor that may heat a relatively permeable formation. Conduit. 512may be placed into opening 514 in hydrocarbon layer 516. Conduit 512 mayhave inner conduit 513. Oxidizing fluid source 508 may provide oxidizingfluid 517 into inner conduit 513. Inner conduit 513 may have criticalflow orifices 515 along its length. Critical flow orifices 515 may bedisposed in a helical pattern (or any other pattern) along a length ofinner conduit 513 in opening 514. For example, critical flow orifices515 may be arranged in a helical pattern with a distance of about 1 m toabout 2.5 m between adjacent orifices. Inner conduit 513 may be sealedat the bottom. Oxidizing fluid 517 may be provided into opening 514through critical flow orifices 515 of inner conduit 513.

[0874] Critical flow orifices 515 may be designed such thatsubstantially the same flow rate of oxidizing fluid 517 may be providedthrough each critical flow orifice. Critical flow orifices 515 may alsoprovide substantially uniform flow of oxidizing fluid 517 along a lengthof conduit 512. Such flow may provide substantially uniform heating ofhydrocarbon layer 516 along the length of conduit 512.

[0875] Packing material 542 may enclose conduit 512 in overburden 540 ofthe formation. Packing material 542 may inhibit flow of fluids fromopening 514 to surface 550. Packing material 542 may include anymaterial that inhibits flow of fluids to surface 550 such as cement orconsolidated sand or gravel. A conduit or opening through the packingmay provide a path for oxidation products to reach the surface.

[0876] Oxidation products 519 typically enter conduit 512 from opening514. Oxidation products 519 may include carbon dioxide, oxides ofnitrogen, oxides of sulfur, carbon monoxide, and/or other productsresulting from a reaction of oxygen with hydrocarbons and/or carbon.Oxidation products 519 may be removed through conduit 512 to surface550. Oxidation product 519 may flow along a face of reaction zone 524 inopening 514 until proximate an upper end of opening 514 where oxidationproduct 519 may flow into conduit 512. Oxidation products 519 may alsobe removed through one or more conduits disposed in opening 514 and/orin hydrocarbon layer 516. For example, oxidation products 519 may beremoved through a second conduit disposed in opening 514. Removingoxidation products 519 through a conduit may inhibit oxidation products519 from flowing to a production well disposed in the formation.Critical flow orifices 515 may also inhibit oxidation products 519 fromentering inner conduit 513.

[0877] A flow rate of oxidation product 519 may be balanced with a flowrate of oxidizing fluid 517 such that a substantially constant pressureis maintained within opening 514. For a 100 m length of heated section,a flow rate of oxidizing fluid may be between about 0.5 standard cubicmeters per minute to about 5 standard cubic meters per minute, or about1.0 standard cubic meters per minute to about 4.0 standard cubic metersper minute, or, for example, about 1.7 standard cubic meters per minute.A flow rate of oxidizing fluid into the formation may be incrementallyincreased during use to accommodate expansion of the reaction zone. Apressure in the opening may be, for example, about 8 bars absolute.Oxidizing fluid 517 may oxidize at least a portion of the hydrocarbonsin heated portion 518 of hydrocarbon layer 516 at reaction zone 524.Heated portion 518 may have been initially heated to a temperaturesufficient to support oxidation by an electric heater, as shown in FIG.52. In some embodiments, an electric heater may be placed inside orstrapped to the outside of conduit 513.

[0878] In certain embodiments, controlling the pressure within opening514 may inhibit oxidation product and/or oxidation fluids from flowinginto the pyrolysis zone of the formation. In some instances, pressurewithin opening 514 may be controlled to be slightly greater than apressure in the formation to allow fluid within the opening to pass intothe formation but to inhibit formation of a pressure gradient thatallows the transport of the fluid a significant distance into theformation.

[0879] Although the heat from the oxidation is transferred to theformation, oxidation product 519 (and excess oxidation fluid such asair) may be inhibited from flowing through the formation and/or to aproduction well within the formation. Instead, oxidation product 519and/or excess oxidation fluid may be removed from the formation. In someembodiments, the oxidation product and/or excess oxidation fluid areremoved through conduit 512. Removing oxidation product and/or excessoxidation fluid may allow heat from oxidation reactions to transfer tothe pyrolysis zone without significant amounts of oxidation productand/or excess oxidation fluid entering the pyrolysis zone.

[0880] In certain embodiments, some pyrolysis product near reaction zone524 may be oxidized in reaction zone 524 in addition to the carbon.Oxidation of the pyrolysis product in reaction zone 524 may provideadditional heating of hydrocarbon layer 516. When oxidation of pyrolysisproduct occurs, oxidation product from the oxidation of pyrolysisproduct may be removed near the reaction zone (e.g., through a conduitsuch as conduit 512). Removing the oxidation product of a pyrolysisproduct may inhibit contamination of other pyrolysis products in theformation with oxidation product.

[0881] Conduit 512 may, in some embodiments, remove oxidation product519 from opening 514 in hydrocarbon layer 516. Oxidizing fluid 517 ininner conduit 513 may be heated by heat exchange with conduit 512. Aportion of heat transfer between conduit 512 and inner conduit 513 mayoccur in overburden section 540. Oxidation product 519 may be cooled bytransferring heat to oxidizing fluid 517. Heating the incoming oxidizingfluid 517 tends to improve the efficiency of heating the formation.

[0882] Oxidizing fluid 517 may transport through reaction zone 524, orheat source zone, by gas phase diffusion and/or convection. Diffusion ofoxidizing fluid 517 through reaction zone 524 may be more efficient atthe relatively high temperatures of oxidation. Diffusion of oxidizingfluid 517 may inhibit development of localized overheating and fingeringin the formation. Diffusion of oxidizing fluid 517 through hydrocarbonlayer 516 is generally a mass transfer process. In the absence of anexternal force, a rate of diffusion for oxidizing fluid 517 may dependupon concentration, pressure, and/or temperature of oxidizing fluid 517within hydrocarbon layer 516. The rate of diffusion may also depend uponthe diffusion coefficient of oxidizing fluid 517 through hydrocarbonlayer 516. The diffusion coefficient may be determined by measurement orcalculation based on the kinetic theory of gases. In general, randommotion of oxidizing fluid 517 may transfer the oxidizing fluid throughhydrocarbon layer 516 from a region of high concentration to a region oflow concentration.

[0883] With time, reaction zone 524 may slowly extend radially togreater diameters from opening 514 as hydrocarbons are oxidized.Reaction zone 524 may, in many embodiments, maintain a relativelyconstant width. For example, reaction zone 524 may extend radially at arate of less than about 0.91 m per year for a relatively permeableformation. Reaction zone 524 may extend at slower rates for hydrocarbonrich formations and at faster rates for formations with more inorganicmaterial since more hydrocarbons per volume are available for combustionin the hydrocarbon rich formations.

[0884] A flow rate of oxidizing fluid 517 into opening 514 may beincreased as a diameter of reaction zone 524 increases to maintain therate of oxidation per unit volume at a substantially steady state. Thus,a temperature within reaction zone 524 may be maintained substantiallyconstant in some embodiments. The temperature within reaction zone 524may be between about 650° C. to about 900° C. or, for example, about760° C. The temperature may be maintained below a temperature thatresults in production of oxides of nitrogen (NO_(x)). Oxides of nitrogenare often produced at temperatures above about 1200° C.

[0885] The temperature within reaction zone 524 may be varied to achievea desired heating rate of selected section 526. The temperature withinreaction zone 524 may be increased or decreased by increasing ordecreasing a flow rate of oxidizing fluid 517 into opening 514. Atemperature of conduit 512, inner conduit 513, and/or any metallurgicalmaterials within opening 514 may be controlled to not exceed a maximumoperating temperature of the material. Maintaining the temperature belowthe maximum operating temperature of a material may inhibit excessivedeformation and/or corrosion of the material.

[0886] An increase in the diameter of reaction zone 524 may allow forrelatively rapid heating of hydrocarbon layer 516. As the diameter ofreaction zone 524 increases, an amount of heat generated per time inreaction zone 524 may also increase. Increasing an amount of heatgenerated per time in the reaction zone will in many instances increasea heating rate of hydrocarbon layer 516 over a period of time, evenwithout increasing the temperature in the reaction zone or thetemperature at conduit 513. Thus, increased heating may be achieved overtime without installing additional heat sources and without increasingtemperatures adjacent to wellbores. In some embodiments, the heatingrates may be increased while allowing the temperatures to decrease(allowing temperatures to decrease may often lengthen the life of theequipment used).

[0887] By utilizing the carbon in the formation as a fuel, the naturaldistributed combustor may save significantly on energy costs. Thus, aneconomical process may be provided for heating formations that wouldotherwise be economically unsuitable for heating by other types of heatsources. Using natural distributed combustors may allow fewer heaters tobe inserted into a formation for heating a desired volume of theformation as compared to heating the formation using other types of heatsources. Heating a formation using natural distributed combustors mayallow for reduced equipment costs as compared to heating the formationusing other types of heat sources.

[0888] Heat generated at reaction zone 524 may transfer by thermalconduction to selected section 526 of hydrocarbon layer 516. Inaddition, generated heat may transfer from a reaction zone to theselected section to a lesser extent by convective heat transfer.Selected section 526, sometimes referred as the “pyrolysis zone,” may besubstantially adjacent to reaction zone 524. Removing oxidation product(and excess oxidation fluid such as air) may allow the pyrolysis zone toreceive heat from the reaction zone without being exposed to oxidationproduct, or oxidants, that are in the reaction zone. Oxidation productand/or oxidation fluids may cause the formation of undesirable productsif they are present in the pyrolysis zone. Removing oxidation productand/or oxidation fluids may allow a reducing environment to bemaintained in the pyrolysis zone.

[0889] In an in situ conversion process embodiment, natural distributedcombustors may be used to heat a formation. FIG. 51 depicts anembodiment of a natural distributed combustor. A flow of oxidizing fluid517 may be controlled along a length of opening 514 or reaction zone524. Opening 514 may be referred to as an “elongated opening,” such thatreaction zone 524 and opening 514 may have a common boundary along adetermined length of the opening. The flow of oxidizing fluid may becontrolled using one or more orifices 515 (the orifices may be criticalflow orifices). The flow of oxidizing fluid may be controlled by adiameter of orifices 515, a number of orifices 515, and/or by a pressurewithin inner conduit 513 (a pressure behind orifices 515). Controllingthe flow of oxidizing fluid may control a temperature at a face ofreaction zone 524 in opening 514. For example, an increased flow ofoxidizing fluid 517 will tend to increase a temperature at the face ofreaction zone 524. Increasing the flow of oxidizing fluid into theopening tends to increase a rate of oxidation of hydrocarbons in thereaction zone. Since the oxidation of hydrocarbons is an exothermicreaction, increasing the rate of oxidation tends to increase thetemperature in the reaction zone.

[0890] In certain natural distributed combustor embodiments, the flow ofoxidizing fluid 517 may be varied along the length of inner conduit 513(e.g., using critical flow orifices 515) such that the temperature atthe face of reaction zone 524 is variable. The temperature at the faceof reaction zone 524, or within opening 514, may be varied to control arate of heat transfer within reaction zone 524 and/or a heating ratewithin selected section 526.

[0891] Increasing the temperature at the face of reaction zone 524 mayincrease the heating rate within selected section 526. A property ofoxidation product 519 may be monitored (e.g., oxygen content, nitrogencontent, temperature, etc.). The property of oxidation product 519 maybe monitored and used to control input properties (e.g., oxidizing fluidinput) into the natural distributed combustor.

[0892] A rate of diffusion of oxidizing fluid 517 through reaction zone524 may vary with a temperature of and adjacent to the reaction zone. Ingeneral, the higher the temperature, the faster a gas will diffusebecause of the increased energy in the gas. A temperature within theopening may be assessed (e.g., measured by a thermocouple) and relatedto a temperature of the reaction zone. The temperature within theopening may be controlled by controlling the flow of oxidizing fluidinto the opening from inner conduit 513. For example, increasing a flowof oxidizing fluid into the opening may increase the temperature withinthe opening. Decreasing the flow of oxidizing fluid into the opening maydecrease the temperature within the opening. In an embodiment, a flow ofoxidizing fluid may be increased until a selected temperature below themetallurgical temperature limits of the equipment being used is reached.For example, the flow of oxidizing fluid can be increased until aworking temperature limit of a metal used in a conduit placed in theopening is reached. The temperature of the metal may be directlymeasured using a thermocouple or other temperature measurement device.

[0893] In a natural distributed combustor embodiment, production ofcarbon dioxide within reaction zone 524 may be inhibited. An increase ina concentration of hydrogen in the reaction zone may inhibit productionof carbon dioxide within the reaction zone. The concentration ofhydrogen may be increased by transferring hydrogen into the reactionzone. In an embodiment, hydrogen may be transferred into the reactionzone from selected section 526. Hydrogen may be produced during thepyrolysis of hydrocarbons in the selected section. Hydrogen may transferby diffusion and/or convection into the reaction zone from the selectedsection. In addition, additional hydrogen may be provided into opening514 or another opening in the formation through a conduit placed in theopening. The additional hydrogen may transfer into the reaction zonefrom opening 514.

[0894] In some natural distributed combustor embodiments, heat may besupplied to the formation from a second heat source in the wellbore ofthe natural distributed combustor. For example, an electric heater(e.g., an insulated conductor heater or a conductor-in-conduit heater)used to preheat a portion of the formation may also be used to provideheat to the formation along with heat from the natural distributedcombustor. In addition, an additional electric heater may be placed inan opening in the formation to provide additional heat to the formation.The electric heater may be used to provide heat to the formation so thatheat provided from the combination of the electric heater and thenatural distributed combustor is maintained at a constant heat inputrate. Heat input into the formation from the electric heater may bevaried as heat input from the natural distributed combustor varies, orvice versa. Providing heat from more than one type of heat source mayallow for substantially uniform heating of the formation.

[0895] In certain in situ conversion process embodiments, up to 10%,25%, or 50% of the total heat input into the formation may be providedfrom electric heaters. A percentage of heat input into the formationfrom electric heaters may be varied depending on, for example,electricity cost, natural distributed combustor heat input, etc. Heatfrom electric heaters can be used to compensate for low heat output fromnatural distributed combustors to maintain a substantially constantheating rate in the formation. If electrical costs rise, more heat maybe generated from natural distributed combustors to reduce the amount ofheat supplied by electric heaters. In some embodiments, heat fromelectric heaters may vary due to the source of electricity (e.g., solaror wind power). In such an embodiments, more or less heat may beprovided by natural distributed combustors to compensate for changes inelectrical heat input.

[0896] In a heat source embodiment, an electric heater may be used toinhibit a natural distributed combustor from “burning out.” A naturaldistributed combustor may “burn out” if a portion of the formation coolsbelow a temperature sufficient to support combustion. Additional heatfrom the electric heater may be needed to provide heat to the portionand/or another portion of the formation to heat a portion to atemperature sufficient to support oxidation of hydrocarbons and maintainthe natural distributed combustor heating process.

[0897] In some natural distributed combustor embodiments, electricheaters may be used to provide more heat to a formation proximate anupper portion and/or a lower portion of the formation. Using theadditional heat from the electric heaters may compensate for heat lossesin the upper and/or lower portions of the formation. Providingadditional heat with the electric heaters proximate the upper and/orlower portions may produce more uniform heating of the formation. Insome embodiments, electric heaters may be used for similar purposes(e.g., provide heat at upper and/or lower portions, provide supplementalheat, provide heat to maintain a minimum combustion temperature, etc.)in combination with other types of fueled heater, such as flamelessdistributed combustors or downhole combustors.

[0898] In some in situ conversion process embodiments, exhaust fluidsfrom a fueled heater (e.g., a natural distributed combustor, or downholecombustor) may be used in an air compressor located at a surface of theformation proximate an opening used for the fueled heater. The exhaustfluids may be used to drive the air compressor and reduce a costassociated with compressing air for use in the fueled heater.Electricity may also be generated using the exhaust fluids in a turbineor similar device. In some embodiments, fluids (e.g., oxidizing fluidand/or fuel) used for one or more fueled heaters may be provided using acompressor or a series of compressors. A compressor may provideoxidizing fluid and/or fuel for one heater or more than one heater. Inaddition, oxidizing fluid and/or fuel may be provided from a centralizedfacility for use in a single heater or more than one heater.

[0899] Pyrolysis of hydrocarbons, or other heat-controlled processes,may take place in heated selected section 526. Selected section 526 maybe at a temperature between about 270° C. and about 400° C. forpyrolysis. The temperature of selected section 526 may be increased byheat transfer from reaction zone 524.

[0900] A temperature within opening 514 may be monitored with athermocouple disposed in opening 514. Alternatively, a thermocouple maybe coupled to conduit 512 and/or disposed on a face of reaction zone524. Power input or oxidant introduced into the formation may becontrolled based upon the monitored temperature to maintain thetemperature in a selected range. The selected range may vary or bevaried depending on location of the thermocouple, a desired heating rateof hydrocarbon layer 516, and other factors. If a temperature withinopening 514 falls below a minimum temperature of the selectedtemperature range, the flow rate of oxidizing fluid 517 may be increasedto increase combustion and thereby increase the temperature withinopening 514.

[0901] In certain embodiments, one or more natural distributedcombustors may be placed along strike of a hydrocarbon layer and/orhorizontally. Placing natural distributed combustors along strike orhorizontally may reduce pressure differentials along the heated lengthof the heat source. Reduced pressure differentials may make thetemperature generated along a length of the heater more uniform andeasier to control.

[0902] In some embodiments, presence of air or oxygen (O₂) in oxidationproduct 519 may be monitored. Alternatively, an amount of nitrogen,carbon monoxide, carbon dioxide, oxides of nitrogen, oxides of sulfur,etc. may be monitored in oxidation product 519. Monitoring thecomposition and/or quantity of exhaust products (e.g., oxidation product519) may be useful for heat balances, for process diagnostics, processcontrol, etc.

[0903]FIG. 53 illustrates a cross-sectional representation of anembodiment of a natural distributed combustor having a second conduit6200 disposed in opening 514 in hydrocarbon layer 516. Second conduit6200 may be used to remove oxidation products from opening 514. Secondconduit 6200 may have orifices 515 disposed along its length. In certainembodiments, oxidation products are removed from an upper region ofopening 514 through orifices 515 disposed on second conduit 6200.Orifices 515 may be disposed along the length of conduit 6200 such thatmore oxidation products are removed from the upper region of opening514.

[0904] In certain natural distributed combustor embodiments, orifices515 on second conduit 6200 may face away from orifices 515 on conduit513. The orientation may inhibit oxidizing fluid provided throughconduit 513 from passing directly into second conduit 6200.

[0905] In some embodiments, conduit 6200 may have a higher density oforifices 515 (and/or relatively larger diameter orifices 515) towardsthe upper region of opening 514. The preferential removal of oxidationproducts from the upper region of opening 514 may produce asubstantially uniform concentration of oxidizing fluid along the lengthof opening 514. Oxidation products produced from reaction zone 524 tendto be more concentrated proximate the upper region of opening 514. Thelarge concentration of oxidation products 519 in the upper region ofopening 514 tends to dilute a concentration of oxidizing fluid 517 inthe upper region. Removing a significant portion of the moreconcentrated oxidation products from the upper region of opening 514 mayproduce a more uniform concentration of oxidizing fluid 517 throughoutopening 514. Having a more uniform concentration of oxidizing fluidthroughout the opening may produce a more uniform driving force foroxidizing fluid to flow into reaction zone 524. The more uniform drivingforce may produce a more uniform oxidation rate within reaction zone524, and thus produce a more uniform heating rate in selected section526 and/or a more uniform temperature within opening 514.

[0906] In a natural distributed combustor embodiment, the concentrationof air and/or oxygen in the reaction zone may be controlled. A more evendistribution of oxygen (or oxygen concentration) in the reaction zonemay be desirable. The rate of reaction may be controlled as a functionof the rate in which oxygen diffuses in the reaction zone. The rate ofoxygen diffusion correlates to the oxygen concentration. Thus,controlling the oxygen concentration in the reaction zone (e.g., bycontrolling oxidizing fluid flow rates, the removal of oxidationproducts along some or all of the length of the reaction zone, and/orthe distribution of the oxidizing fluid along some or all of the lengthof the reaction zone) may control oxygen diffusion in the reaction zoneand thereby control the reaction rates in the reaction zone.

[0907] In the embodiment shown in FIG. 54, conductor 580 is placed inopening 514. Conductor 580 may extend from first end 6170 of opening 514to second end 6172 of opening 514. In certain embodiments, conductor 580may be placed in opening 514 within hydrocarbon layer 516. One or morelow resistance sections 584 may be coupled to conductor 580 and used inoverburden 540. In some embodiments, conductor 580 and/or low resistancesections 584 may extend above the surface of the formation.

[0908] In some heat source embodiments, an electric current may beapplied to conductor 580 to increase a temperature of the conductor.Heat may transfer from conductor 580 to heated portion 518 ofhydrocarbon layer 516. Heat may transfer from conductor 580 to heatedportion 518 substantially by radiation. Some heat may also transfer byconvection or conduction. Current may be provided to the conductor untila temperature within heated portion 518 is sufficient to support theoxidation of hydrocarbons within the heated portion. As shown in FIG.54, oxidizing fluid may be provided into conductor 580 from oxidizingfluid source 508 at one or both ends 6170, 6172 of opening 514. A flowof the oxidizing fluid from conductor 580 into opening 514 may becontrolled by orifices 515. The orifices may be critical flow orifices.The flow of oxidizing fluid from orifices 515 may be controlled by adiameter of the orifices, a number of orifices, and/or by a pressurewithin conductor 580 (i.e., a pressure behind the orifices).

[0909] Reaction of oxidizing fluids with hydrocarbons in reaction zone524 may generate heat. The rate of heat generated in reaction zone 524may be controlled by a flow rate of the oxidizing fluid into theformation, the rate of diffusion of oxidizing fluid through the reactionzone, and/or a removal rate of oxidation products from the formation. Inan embodiment, oxidation products from the reaction of oxidizing fluidwith hydrocarbons in the formation are removed through one or both endsof opening 514. In some embodiments, a conduit may be placed in opening514 to remove oxidation products. All or portions of the oxidationproducts may be recycled and/or reused in other oxidation type heaters(e.g., natural distributed combustors, surface burners, downholecombustors, etc.). Heat generated in reaction zone 524 may transfer to asurrounding portion (e.g., selected section) of the formation. Thetransfer of heat between reaction zone 524 and selected section may besubstantially by conduction. In certain embodiments, the transferredheat may increase a temperature of the selected section above a minimummobilization temperature of the hydrocarbons and/or a minimum pyrolysistemperature of the hydrocarbons.

[0910] In some heat source embodiments, a conduit may be placed in theopening. The opening may extend through the formation contacting asurface of the earth at a first location and a second location.Oxidizing fluid may be provided to the conduit from the oxidizing fluidsource at the first location and/or the second location after a portionof the formation that has been heated to a temperature sufficient tosupport oxidation of hydrocarbons by the oxidizing fluid.

[0911]FIG. 55 illustrates an embodiment of a section of overburden witha natural distributed combustor as described in FIG. 51. Overburdencasing 541 may be disposed in overburden 540 of hydrocarbon layer 516.Overburden casing 541 may be surrounded by materials (e.g., aninsulating material such as cement) that inhibit heating of overburden540. Overburden casing 541 may be made of a metal material such as, butnot limited to, carbon steel or 304 stainless steel.

[0912] Overburden casing 541 may be placed in reinforcing material 544in overburden 540. Reinforcing material 544 may be, but is not limitedto, cement, gravel, sand, and/or concrete. Packing material 542 may bedisposed between overburden casing 541 and opening 514 in the formation.Packing material 542 may be any substantially non-porous material (e.g.,cement, concrete, grout, etc.). Packing material 542 may inhibit flow offluid outside of conduit 512 and between opening 514 and surface 550.Inner conduit 513 may introduce fluid into opening 514 in hydrocarbonlayer 516. Conduit 512 may remove combustion product (or excessoxidation fluid) from opening 514 in hydrocarbon layer 516. Diameter ofconduit 512 may be determined by an amount of the combustion productproduced by oxidation in the natural distributed combustor. For example,a larger diameter may be required for a greater amount of exhaustproduct produced by the natural distributed combustor heater.

[0913] In some heat source embodiments, a portion of the formationadjacent to a wellbore may be heated to a temperature and at a heatingrate that converts hydrocarbons to coke or char adjacent to the wellboreby a first heat source. Coke and/or char may be formed at temperaturesabove about 400° C. In the presence of an oxidizing fluid, the coke orchar will oxidize. The wellbore may be used as a natural distributedcombustor subsequent to the formation of coke and/or char. Heat may begenerated from the oxidation of coke or char.

[0914]FIG. 56 illustrates an embodiment of a natural distributedcombustor heater. Insulated conductor 562 may be coupled to conduit 532and placed in opening 514 in hydrocarbon layer 516. Insulated conductor562 may be disposed internal to conduit 532 (thereby allowing retrievalof insulated conductor 562), or, alternately, coupled to an externalsurface of conduit 532. Insulating material for the conductor mayinclude, but is not limited to, mineral coating and/or ceramic coating.Conduit 532 may have critical flow orifices 515 disposed along itslength within opening 514. Electrical current may be applied toinsulated conductor 562 to generate radiant heat in opening 514. Conduit532 may serve as a return for current. Insulated conductor 562 may heatportion 518 of hydrocarbon layer 516 to a temperature sufficient tosupport oxidation of hydrocarbons.

[0915] Oxidizing fluid source 508 may provide oxidizing fluid intoconduit 532. Oxidizing fluid may be provided into opening 514 throughcritical flow orifices 515 in conduit 532. Oxidizing fluid may oxidizeat least a portion of the hydrocarbon layer in reaction zone 524. Aportion of heat generated at reaction zone 524 may transfer to selectedsection 526 by convection, radiation, and/or conduction. Oxidationproduct may be removed through a separate conduit placed in opening 514or through opening 543 in overburden casing 541.

[0916]FIG. 57 illustrates an embodiment of a natural distributedcombustor heater with an added fuel conduit. Fuel conduit 536 may beplaced in opening 514. Fuel conduit may be placed adjacent to conduit533 in certain embodiments. Fuel conduit 536 may have critical floworifices 535 along a portion of the length within opening 514. Conduit533 may have critical flow orifices 515 along a portion of the lengthwithin opening 514. The critical flow orifices 535, 515 may bepositioned so that a fuel fluid provided through fuel conduit 536 and anoxidizing fluid provided through conduit 533 do not react to heat thefuel conduit and the conduit. Heat from reaction of the fuel fluid withoxidizing fluid may heat fuel conduit 536 and/or conduit 533 to atemperature sufficient to begin melting metallurgical materials in fuelconduit 536 and/or conduit 533 if the reaction takes place proximatefuel conduit 536 and/or conduit 533. Critical flow orifices 535 on fuelconduit 536 and critical flow orifices 515 on conduit 533 may bepositioned so that the fuel fluid and the oxidizing fluid do not reactproximate the conduits. For example, conduits 536 and 533 may bepositioned such that orifices that-spiral around the conduits areoriented in opposite directions.

[0917] Reaction of the fuel fluid and the oxidizing fluid may produceheat. In some embodiments, the fuel fluid may be methane, ethane,hydrogen, or synthesis gas that is generated by in situ conversion inanother part of the formation. The produced heat may heat portion 518 toa temperature sufficient to support oxidation of hydrocarbons. Uponheating of portion 518 to a temperature sufficient to support oxidation,a flow of fuel fluid into opening 514 may be turned down or may beturned off. In some embodiments, the supply of fuel may be continuedthroughout the heating of the formation.

[0918] The oxidizing fluid may oxidize at least a portion of thehydrocarbons at reaction zone 524. Generated heat may transfer heat toselected section 526 by radiation, convection, and/or conduction. Anoxidation product may be removed through a separate conduit placed inopening 514 or through opening 543 in overburden casing 541.

[0919]FIG. 52 illustrates an embodiment of a system that may heat arelatively permeable formation. Electric heater 510 may be disposedwithin opening 514 in hydrocarbon layer 516. Opening 514 may be formedthrough overburden 540 into hydrocarbon layer 516. Opening 514 may be atleast about 5 cm in diameter. Opening 514 may, as an example, have adiameter of about 13 cm. Electric heater 510 may heat at least portion518 of hydrocarbon layer 516 to a temperature sufficient to supportoxidation (e.g., about 260° C.). Portion 518 may have a width of about 1m. An oxidizing fluid may be provided into the opening through conduit512 or any other appropriate fluid transfer mechanism. Conduit 512 mayhave critical flow orifices 515 disposed along a length of the conduit.

[0920] Conduit 512 may be a pipe or tube that provides the oxidizingfluid into opening 514 from oxidizing fluid source 508. In anembodiment, a portion of conduit 512 that may be exposed to hightemperatures is a stainless steel tube and a portion of the conduit thatwill not be exposed to high temperatures (i.e., a portion of the tubethat extends through the overburden) is carbon steel. The oxidizingfluid may include air or any other oxygen containing fluid (e.g.,hydrogen peroxide, oxides of nitrogen, ozone). Mixtures of oxidizingfluids may be used. An oxidizing fluid mixture may be a fluid includingfifty percent oxygen and fifty percent nitrogen. In some embodiments,the oxidizing fluid may include compounds that release oxygen whenheated, such as hydrogen peroxide. The oxidizing fluid may oxidize atleast a portion of the hydrocarbons in the formation.

[0921]FIG. 58 illustrates an embodiment of a system that heats arelatively permeable formation. Heat exchanger 520 may be disposedexternal to opening 514 in hydrocarbon layer 516. Opening 514 may beformed through overburden 540 into hydrocarbon layer 516. Heat exchanger520 may provide heat from another surface process, or it may include aheater (e.g., an electric or combustion heater). Oxidizing fluid source508 may provide an oxidizing fluid to heat exchanger 520. Heat exchanger520 may heat an oxidizing fluid (e.g., above 200° C. or to a temperaturesufficient to support oxidation of hydrocarbons). The heated oxidizingfluid may be provided into opening 514 through conduit 521. Conduit 521may have critical flow orifices 515 disposed along a length of theconduit. The heated oxidizing fluid may heat, or at least contribute tothe heating of, at least portion 518 of the formation to a temperaturesufficient to support oxidation of hydrocarbons. The oxidizing fluid mayoxidize at least a portion of the hydrocarbons in the formation. Aftertemperature in the formation is sufficient to support oxidation, use ofheat exchanger 520 may be reduced or phased out.

[0922] An embodiment of a natural distributed combustor may include asurface combustor (e.g., a flame-ignited heater). A fuel fluid may beoxidized in the combustor. The oxidized fuel fluid may be provided intoan opening in the formation from the heater through a conduit. Oxidationproducts and unreacted fuel may return to the surface through anotherconduit. In some embodiments, one of the conduits may be placed withinthe other conduit. The oxidized fuel fluid may heat, or contribute tothe heating of, a portion of the formation to a temperature sufficientto support oxidation of hydrocarbons. Upon reaching the temperaturesufficient to support oxidation, the oxidized fuel fluid may be replacedwith an oxidizing fluid. The oxidizing fluid may oxidize at least aportion of the hydrocarbons at a reaction zone within the formation.

[0923] An electric heater may heat a portion of the relatively permeableformation to a temperature sufficient to support oxidation ofhydrocarbons. The portion may be proximate or substantially adjacent tothe opening in the formation. The portion may radially extend a width ofless than approximately 1 m from the opening. An oxidizing fluid may beprovided to the opening for oxidation of hydrocarbons. Oxidation of thehydrocarbons may heat the relatively permeable formation in a process ofnatural distributed combustion. Electrical current applied to theelectric heater may subsequently be reduced or may be turned off.Natural distributed combustion may be used in conjunction with anelectric heater to provide a reduced input energy cost method to heatthe relatively permeable formation compared to using only an electricheater.

[0924] An insulated conductor heater may be a heater element of a heatsource. In an embodiment of an insulated conductor heater, the insulatedconductor heater is a mineral insulated cable or rod. An insulatedconductor heater may be placed in an opening in a relatively permeableformation. The insulated conductor heater may be placed in an uncasedopening in the relatively permeable formation. Placing the heater in anuncased opening in the relatively permeable formation may allow heattransfer from the heater to the formation by radiation as well asconduction. Using an uncased opening may facilitate retrieval of theheater from the well, if necessary. Using an uncased opening maysignificantly reduce heat source capital cost by eliminating a need fora portion of casing able to withstand high temperature conditions. Insome heat source embodiments, an insulated conductor heater may beplaced within a casing in the formation; may be cemented within theformation; or may be packed in an opening with sand, gravel, or otherfill material. The insulated conductor heater may be supported on asupport member positioned within the opening. The support member may bea cable, rod, or a conduit (e.g., a pipe). The support member may bemade of a metal, ceramic, inorganic material, or combinations thereof.Portions of a support member may be exposed to formation fluids and heatduring use, so the support member may be chemically resistant andthermally resistant.

[0925] Ties, spot welds, and/or other types of connectors may be used tocouple the insulated conductor heater to the support member at variouslocations along a length of the insulated conductor heater. The supportmember may be attached to a wellhead at an upper surface of theformation. In an embodiment of an insulated conductor heater, theinsulated conductor heater is designed to have sufficient structuralstrength so that a support member is not needed. The insulated conductorheater will in many instances have some flexibility to inhibit thermalexpansion damage when heated or cooled.

[0926] In certain embodiments, insulated conductor heaters may be placedin wellbores without support members and/or centralizers. An insulatedconductor heater without support members and/or centralizers may have asuitable combination of temperature and corrosion resistance, creepstrength, length, thickness (diameter), and metallurgy that will inhibitfailure of the insulated conductor during use. In some in situconversion embodiments, insulated conductors that are heated to aworking temperature of about 700° C., are less than about 150 m inlength, are made of 310 stainless steel may be used without supportmembers.

[0927]FIG. 59 depicts a perspective view of an end portion of anembodiment of insulated conductor heater 562. An insulated conductorheater may have any desired cross-sectional shape, such as, but notlimited to round (as shown in FIG. 59), triangular, ellipsoidal,rectangular, hexagonal, or irregular shape. An insulated conductorheater may include conductor 575, electrical insulation 576, and sheath577. Conductor 575 may resistively heat when an electrical currentpasses through the conductor. An alternating or direct current may beused to heat conductor 575. In an embodiment, a 60-cycle AC current isused.

[0928] In some embodiments, electrical insulation 576 may inhibitcurrent leakage and arcing to sheath 577. Electrical insulation 576 mayalso thermally conduct heat generated in conductor 575 to sheath 577.Sheath 577 may radiate or conduct heat to the formation. Insulatedconductor heater 562 may be 1000 m or more in length. In an embodimentof an insulated conductor heater, insulated conductor heater 562 mayhave a length from about 15 m to about 950 m. Longer or shorterinsulated conductors may also be used to meet specific applicationneeds. In embodiments of insulated conductor heaters, purchasedinsulated conductor heaters have lengths of about 100 m to 500 m (e.g.,230 m). In certain embodiments, dimensions of sheaths and/or conductorsof an insulated conductor may be selected so that the insulatedconductor has enough strength to be self supporting even at upperworking temperature limits. Such insulated cables may be suspended fromwellheads or supports positioned near an interface between an overburdenand a relatively permeable formation without the need for supportmembers extending into the hydrocarbon formation along with theinsulated conductors.

[0929] In an embodiment, a higher frequency current may be used to takeadvantage of the skin effect in certain metals. In some embodiments, a60 cycle AC current may be used in combination with conductors made ofmetals that exhibit pronounced skin effects. For example, ferromagneticmetals like iron alloys and nickel may exhibit a skin effect. The skineffect confines the current to a region close to the outer surface ofthe conductor, thereby effectively increasing the resistance of theconductor. A high resistance may be desired to decrease the operatingcurrent, minimize ohmic losses in surface cables, and minimize the costof surface facilities.

[0930] Insulated conductor 562 may be designed to operate at powerlevels of up to about 1650 watts/meter. Insulated conductor heater 562may typically operate at a power level between about 500 watts/meter andabout 1150 watts/meter when heating a formation. Insulated conductorheater 562 may be designed so that a maximum voltage level at a typicaloperating temperature does not cause substantial thermal and/orelectrical breakdown of electrical insulation 576. The insulatedconductor heater 562 may be designed so that sheath 577 does not exceeda temperature that will result in a significant reduction in corrosionresistance properties of the sheath material.

[0931] In an embodiment of insulated conductor heater 562, conductor 575may be designed to reach temperatures within a range between about 650°C. and about 870° C. The sheath 577 may be designed to reachtemperatures within a range between about 535° C. and about 760° C.Insulated conductors having other operating ranges may be formed to meetspecific operational requirements. In an embodiment of insulatedconductor heater 562, conductor 575 is designed to operate at about 760°C., sheath 577 is designed to operate at about 650° C., and theinsulated conductor heater is designed to dissipate about 820watts/meter.

[0932] Insulated conductor heater 562 may have one or more conductors575. For example, a single insulated conductor heater may have threeconductors within electrical insulation that are surrounded by a sheath.FIG. 59 depicts insulated conductor heater 562 having a single conductor575. The conductor may be made of metal. The material used to form aconductor may be, but is not limited to, nichrome, nickel, and a numberof alloys made from copper and nickel in increasing nickelconcentrations from pure copper to Alloy 30, Alloy 60, Alloy 180, andMonel. Alloys of copper and nickel may advantageously have betterelectrical resistance properties than substantially pure nickel orcopper.

[0933] In an embodiment, the conductor may be chosen to have a diameterand a resistivity at operating temperatures such that its resistance, asderived from Ohm's law, makes it electrically and structurally stablefor the chosen power dissipation per meter, the length of the heater,and/or the maximum voltage allowed to pass through the conductor. Insome embodiments, the conductor may be designed using Maxwell'sequations to make use of skin effect.

[0934] The conductor may be made of different materials along a lengthof the insulated conductor heater. For example, a first section of theconductor may be made of a material that has a significantly lowerresistance than a second section of the conductor. The first section maybe placed adjacent to a formation layer that does not need to be heatedto as high a temperature as a second formation layer that is adjacent tothe second section. The resistivity of various sections of conductor maybe adjusted by having a variable diameter and/or by having conductorsections made of different materials.

[0935] A diameter of conductor 575 may typically be between about 1.3 mmto about 10.2 mm. Smaller or larger diameters may also be used to haveconductors with desired resistivity characteristics. In an embodiment ofan insulated conductor heater, the conductor is made of Alloy 60 thathas a diameter of about 5.8 mm.

[0936] Electrical insulator 576 of insulated conductor heater 562 may bemade of a variety of materials. Pressure may be used to place electricalinsulator powder between conductor 575 and sheath 577. Low flowcharacteristics and other properties of the powder and/or the sheathsand conductors may inhibit the powder from flowing out of the sheaths.Commonly used powders may include, but are not limited to, MgO, Al₂O₃,Zirconia, BeO, different chemical variations of Spinels, andcombinations thereof. MgO may provide good thermal conductivity andelectrical insulation properties. The desired electrical insulationproperties include low leakage current and high dielectric strength. Alow leakage current decreases the possibility of thermal breakdown andthe high dielectric strength decreases the possibility of arcing acrossthe insulator. Thermal breakdown can occur if the leakage current causesa progressive rise in the temperature of the insulator leading also toarcing across the insulator. An amount of impurities 578 in theelectrical insulator powder may be tailored to provide requireddielectric strength and a low level of leakage current. Impurities 578added may be, but are not limited to, CaO, Fe₂O₃, Al₂O₃, and other metaloxides. Low porosity of the electrical insulation tends to reduceleakage current and increase dielectric strength. Low porosity may beachieved by increased packing of the MgO powder during fabrication or byfilling of the pore space in the MgO powder with other granularmaterials, for example, Al₂O₃.

[0937] Impurities 578 added to the electrical insulator powder may haveparticle sizes that are smaller than the particle sizes of the powderedelectrical insulator. The small particles may occupy pore space betweenthe larger particles of the electrical insulator so that the porosity ofthe electrical insulator is reduced. Examples of powdered electricalinsulators that may be used to form electrical insulation 576 are “H”mix manufactured by Idaho Laboratories Corporation (Idaho Falls, Id.) orStandard MgO used by Pyrotenax Cable Company (Trenton, Ontario) for hightemperature applications. In addition, other powdered electricalinsulators may be used.

[0938] Sheath 577 of insulated conductor heater 562 may be an outermetallic layer. Sheath 577 may be in contact with hot formation fluids.Sheath 577 may need to be made of a material having a high resistance tocorrosion at elevated temperatures. Alloys that may be used in a desiredoperating temperature range of the sheath include, but are not limitedto, 304 stainless steel, 310 stainless steel, Incoloy 800, and Inconel600. The thickness of the sheath has to be sufficient to last for threeto ten years in a hot and corrosive environment. A thickness of thesheath may generally vary between about 1 mm and about 2.5 mm. Forexample, a 1.3 mm thick, 310 stainless steel outer layer may be used assheath 577 to provide good chemical resistance to sulfidation corrosionin a heated zone of a formation for a period of over 3 years. Larger orsmaller sheath thicknesses may be used to meet specific applicationrequirements.

[0939] An insulated conductor heater may be tested after fabrication.The insulated conductor heater may be required to withstand 2-3 times anoperating voltage at a selected operating temperature. Also, selectedsamples of produced insulated conductor heaters may be required towithstand 1000 VAC at 760° C. for one month.

[0940] As illustrated in FIG. 60, short flexible transition conductor571 may be connected to lead-in conductor 572 using connection 569 madeduring heater installation in the field. Transition conductor 571 may bea flexible, low resistivity, stranded copper cable that is surrounded byrubber or polymer insulation. Transition conductor 571 may typically bebetween about 1.5 m and about 3 m, although longer or shorter transitionconductors may be used to accommodate particular needs. Temperatureresistant cable may be used as transition conductor 571. Transitionconductor 571 may also be connected to a short length of an insulatedconductor heater that is less resistive than a primary heating sectionof the insulated conductor heater. The less resistive portion of theinsulated conductor heater may be referred to as “cold pin” 568.

[0941] Cold pin 568 may be designed to dissipate about one-tenth toabout one-fifth of the power per unit length as is dissipated in a unitlength of the primary heating section. Cold pins may typically bebetween about 1.5 m and about 15 m, although shorter or longer lengthsmay be used to accommodate specific application needs. In an embodiment,the conductor of a cold pin section is copper with a diameter of about6.9 mm and a length of 9.1 m. The electrical insulation is the same typeof insulation used in the primary heating section. A sheath of the coldpin may be made of Inconel 600. Chloride corrosion cracking in the coldpin region may occur, so a chloride corrosion resistant metal such asInconel 600 may be used as the sheath.

[0942] As illustrated in FIG. 60, small, epoxy filled canister 573 maybe used to create a connection between transition conductor 571 and coldpin 568. Cold pins 568 may be connected to the primary heating sectionsof insulated conductor 562 heaters by “splices” 567. The length of coldpin 568 may be sufficient to significantly reduce a temperature ofinsulated conductor heater 562. The heater section of the insulatedconductor heater 562 may operate from about 530° C. to about 760° C.,splice 567 may be at a temperature from about 260° C. to about 370° C.,and the temperature at the lead-in cable connection to the cold pin maybe from about 40° C. to about 90° C. In addition to a cold pin at a topend of the insulated conductor heater, a cold pin may also be placed ata bottom end of the insulated conductor heater. The cold pin at thebottom end may in many instances make a bottom termination easier tomanufacture.

[0943] Splice material may have to withstand a temperature equal to halfof a target zone operating temperature. Density of electrical insulationin the splice should in many instances be high enough to withstand therequired temperature and the operating voltage.

[0944] Splice 567 may be required to withstand 1000 VAC at 480° C.Splice material may be high temperature splices made by IdahoLaboratories Corporation or by Pyrotenax Cable Company. A splice may bean internal type of splice or an external splice. An internal splice istypically made without welds on the sheath of the insulated conductorheater. The lack of weld on the sheath may avoid potential weak spots(mechanical and/or electrical) on the insulated cable heater. Anexternal splice is a weld made to couple sheaths of two insulatedconductor heaters together. An external splice may need to be leaktested prior to insertion of the insulated cable heater into aformation. Laser welds or orbital TIG (tungsten inert gas) welds may beused to form external splices. An additional strain relief assembly maybe placed around an external splice to improve the splice's resistanceto bending and to protect the external splice against partial or totalparting.

[0945] In certain embodiments, an insulated conductor assembly, such asthe assembly depicted in FIG. 61 and FIG. 60, may have to withstand ahigher operating voltage than normally would be used. For example, forheaters greater than about 700 m in length, voltages greater than about2000 V may be needed for generating heat with the insulated conductor,as compared to voltages of about 480 V that may be used with heatershaving lengths of less than about 225 m. In such cases, it may beadvantageous to form insulated conductor 562, cold pin 568, transitionconductor 571, and lead-in conductor 572 into a single insulatedconductor assembly. In some embodiments, cold pin 568 and canister 573may not be required as shown in FIG. 60. In such an embodiment, splice567 can be used to directly couple insulated conductor 562 to transitionconductor 571.

[0946] In a heat source embodiment, insulated conductor 562, transitionconductor 571, and lead-in conductor 572 each include insulatedconductors of varying resistance. Resistance of the conductors may bevaried, for example, by altering a type of conductor, a diameter of aconductor, and/or a length of a conductor. In an embodiment, diametersof insulated conductor 562, transition conductor 571, and lead-inconductor 572 are different. Insulated conductor 562 may have a diameterof 6 mm, transition conductor 571 may have a diameter of 7 mm, andlead-in conductor 572 may have a diameter of 8 mm. Smaller or largerdiameters may be used to accommodate site conditions (e.g., heatingrequirements or voltage requirements). Insulated conductor 562 may havea higher resistance than either transition conductor 571 or lead-inconductor 572, such that more heat is generated in the insulatedconductor. Also, transition conductor 571 may have a resistance betweena resistance of insulated conductor 562 and lead-in conductor 572.Insulated conductor 562, transition conductor 571, and lead-in conductor572 may be coupled using splice 567 and/or connection 569. Splice 567and/or connection 569 may be required to withstand relatively largeoperating voltages depending on a length of insulated conductor 562and/or lead-in conductor 572. Splice 567 and/or connection 569 mayinhibit arcing and/or voltage breakdowns within the insulated conductorassembly. Using insulated conductors for each cable within an insulatedconductor assembly may allow for higher operating voltages within theassembly.

[0947] An insulated conductor assembly may include heating sections,cold pins, splices, termination canisters and flexible transitionconductors. The insulated conductor assembly may need to be examined andelectrically tested before installation of the assembly into an openingin a formation. The assembly may need to be examined for competent weldsand to make sure that there are no holes in the sheath anywhere alongthe whole heater (including the heated section, the cold-pins, thesplices, and the termination cans). Periodic X-ray spot checking of thecommercial product may need to be made. The whole cable may be immersedin water prior to electrical testing. Electrical testing of the assemblymay need to show more than 2000 megaohms at 500 VAC at room temperatureafter water immersion. In addition, the assembly may need to beconnected to 1000 VAC and show less than about 10 microamps per meter ofresistive leakage current at room temperature. In addition, a check onleakage current at about 760° C. may need to show less than about 0.4milliamps per meter.

[0948] A number of companies manufacture insulated conductor heaters.Such manufacturers include, but are not limited to, MI CableTechnologies (Calgary, Alberta), Pyrotenax Cable Company (Trenton,Ontario), Idaho Laboratories Corporation (Idaho Falls, Id.), and Watlow(St. Louis, Mo.). As an example, an insulated conductor heater may beordered from Idaho Laboratories as cable model 355-A90-310-“H”30′/750′/30′ with Inconel 600 sheath for the cold-pins, three phase Yconfiguration and bottom jointed conductors. The specification for theheater may also include 1000 VAC, 1400° F. quality cable. The designator355 specifies the cable OD (0.355″); A90 specifies the conductormaterial; 310 specifies the heated zone sheath alloy (SS 310); “H”specifies the MgO mix; and 30′/750′/30′ specifies about a 230 m heatedzone with cold-pins top and bottom having about 9 m lengths. A similarpart number with the same specification using high temperature Standardpurity MgO cable may be ordered from Pyrotenax Cable Company.

[0949] One or more insulated conductor heaters may be placed within anopening in a formation to form a heat source or heat sources. Electricalcurrent may be passed through each insulated conductor heater in theopening to heat the formation. Alternately, electrical current may bepassed through selected insulated conductor heaters in an opening. Theunused conductors may be backup heaters. Insulated conductor heaters maybe electrically coupled to a power source in any convenient manner. Eachend of an insulated conductor heater may be coupled to lead-in cablesthat pass through a wellhead. Such a configuration typically has a 180°bend (a “hairpin” bend) or turn located near a bottom of the heatsource. An insulated conductor heater that includes a 180° bend or turnmay not require a bottom termination, but the 180° bend or turn may bean electrical and/or structural weakness in the heater. Insulatedconductor heaters may be electrically coupled together in series, inparallel, or in series and parallel combinations. In some embodiments ofheat sources, electrical current may pass into the conductor of aninsulated conductor heater and may be returned through the sheath of theinsulated conductor heater by connecting conductor 575 to sheath 577 atthe bottom of the heat source.

[0950] In the embodiment of a heat source depicted in FIG. 61, threeinsulated conductor heaters 562 are electrically coupled in a 3-phase Yconfiguration to a power supply. The power supply may provide 60 cycleAC current to the electrical conductors. No bottom connection may berequired for the insulated conductor heaters. Alternately, all threeconductors of the three phase circuit may be connected together near thebottom of a heat source opening. The connection may be made directly atends of heating sections of the insulated conductor heaters or at endsof cold pins coupled to the heating sections at the bottom of theinsulated conductor heaters. The bottom connections may be made withinsulator filled and sealed canisters or with epoxy filled canisters.The insulator may be the same composition as the insulator used as theelectrical insulation.

[0951] The three insulated conductor heaters depicted in FIG. 61 may becoupled to support member 564 using centralizers 566. Alternatively, thethree insulated conductor heaters may be strapped directly to thesupport tube using metal straps. Centralizers 566 may maintain alocation or inhibit movement of insulated conductor heaters 562 onsupport member 564. Centralizers 566 may be made of metal, ceramic, orcombinations thereof. The metal may be stainless steel or any other typeof metal able to withstand a corrosive and hot environment. In someembodiments, centralizers 566 may be bowed metal strips welded to thesupport member at distances less than about 6 m. A ceramic used incentralizer 566 may be, but is not limited to, Al₂O₃, MgO, or otherinsulator. Centralizers 566 may maintain a location of insulatedconductor heaters 562 on support member 564 such that movement ofinsulated conductor heaters is inhibited at operating temperatures ofthe insulated conductor heaters.

[0952] Insulated conductor heaters 562 may also be somewhat flexible towithstand expansion of support member 564 during heating. Support member564, insulated conductor heater 562, and centralizers 566 may be placedin opening 514 in hydrocarbon layer 516. Insulated conductor heaters 562may be coupled to bottom conductor junction 570 using cold pintransition conductor 568. Bottom conductor junction 570 may electricallycouple each insulated conductor heater 562 to each other. Bottomconductor junction 570 may include materials that are electricallyconducting and do not melt at temperatures found in opening 514. Coldpin transition conductor 568 may be an insulated conductor heater havinglower electrical resistance than insulated conductor heater 562. Asillustrated in FIG. 60, cold pin 568 may be coupled to transitionconductor 571 and insulated conductor heater 562. Cold pin transitionconductor 568 may provide a temperature transition between transitionconductor 571 and insulated conductor heater 562.

[0953] Lead-in conductor 572 may be coupled to wellhead 590 to provideelectrical power to insulated conductor heater 562. Lead-in conductor572 may be made of a relatively low electrical resistance conductor suchthat relatively little heat is generated from electrical current passingthrough lead-in conductor 572. In some embodiments, the lead-inconductor is a rubber or polymer insulated stranded copper wire. In someembodiments, the lead-in conductor is a mineral-insulated conductor witha copper core. Lead-in conductor 572 may couple to wellhead 590 atsurface 550 through a sealing flange located between overburden 540 andsurface 550. The sealing flange may inhibit fluid from escaping fromopening 514 to surface 550.

[0954] Packing material 542 may be placed between overburden casing 541and opening 514. In some embodiments, cement 544 may secure overburdencasing 541 to overburden 540. In an embodiment of a heat source,overburden casing is a 7.6 cm (3-inch) diameter carbon steel, schedule40 pipe. Packing material 542 may inhibit fluid from flowing fromopening 514 to surface 550. Cement 544 may include, for example, Class Gor Class H Portland cement mixed with silica flour for improved hightemperature performance, slag or silica flour, and/or a mixture thereof(e.g., about 1.58 grams per cubic centimeter slag/silica flour). In someheat source embodiments, cement 544 extends radially a width of fromabout 5 cm to about 25 cm. In some embodiments, cement 544 may extendradially a width of about 10 cm to about 15 cm. Cement 544 may inhibitheat transfer from conductor 564 into overburden 540.

[0955] In certain embodiments, one or more conduits may be provided tosupply additional components (e.g., nitrogen, carbon dioxide, reducingagents such as gas containing hydrogen, etc.) to formation openings, tobleed off fluids, and/or to control pressure. Formation pressures tendto be highest near heating sources. Providing pressure control equipmentin heat sources may be beneficial. In some embodiments, adding areducing agent proximate the heating source assists in providing a morefavorable pyrolysis environment (e.g., a higher hydrogen partialpressure). Since permeability and porosity tend to increase more quicklyproximate the heating source, it is often optimal to add a reducingagent proximate the heating source so that the reducing agent can moreeasily move into the formation.

[0956] Conduit 5000, depicted in FIG. 61, may be provided to add gasfrom gas source 5003, through valve 5001, and into opening 514. Opening5004 is provided in packing material 542 to allow gas to pass intoopening 514. Conduit 5000 and valve 5002 may be used at different timesto bleed off pressure and/or control pressure proximate opening 514.Conduit 5010, depicted in FIG. 63, may be provided to add gas from gassource 5013, through valve 5011, and into opening 514. An opening isprovided in cement 544 to allow gas to pass into opening 514. Conduit5010 and valve 5012 may be used at different times to bleed off pressureand/or control pressure proximate opening 514. It is to be understoodthat any of the heating sources described herein may also be equippedwith conduits to supply additional components, bleed off fluids, and/orto control pressure.

[0957] As shown in FIG. 61, support member 564 and lead-in conductor 572may be coupled to wellhead 590 at surface 550 of the formation. Surfaceconductor 545 may enclose cement 544 and couple to wellhead 590.Embodiments of surface conductor 545 may have an outer diameter of about10.16 cm to about 30.48 cm or, for example, an outer diameter of about22 cm. Embodiments of surface conductors may extend to depths ofapproximately 3 m to approximately 515 m into an opening in theformation. Alternatively, the surface conductor may extend to a depth ofapproximately 9 m into the opening. Electrical current may be suppliedfrom a power source to insulated conductor heater 562 to generate heatdue to the electrical resistance of conductor 575 as illustrated in FIG.59. As an example, a voltage of about 330 volts and a current of about266 amps are supplied to insulated conductor 562 to generate a heat ofabout 1150 watts/meter in insulated conductor heater 562. Heat generatedfrom the three insulated conductor heaters 562 may transfer (e.g., byradiation) within opening 514 to heat at least a portion of thehydrocarbon layer 516.

[0958] An appropriate configuration of an insulated conductor heater maybe determined by optimizing a material cost of the heater based on alength of heater, a power required per meter of conductor, and a desiredoperating voltage. In addition, an operating current and voltage may bechosen to optimize the cost of input electrical energy in conjunctionwith a material cost of the insulated conductor heaters. For example, asinput electrical energy increases, the cost of materials needed towithstand the higher voltage may also increase. The insulated conductorheaters may generate radiant heat of approximately 650 watts/meter ofconductor to approximately 1650 watts/meter of conductor. The insulatedconductor heater may operate at a temperature between approximately 530°C. and approximately 760° C. within a formation.

[0959] Heat generated by an insulated conductor heater may heat at leasta portion of a relatively permeable formation. In some embodiments, heatmay be transferred to the formation substantially by radiation of thegenerated heat to the formation. Some heat may be transferred byconduction or convection of heat due to gases present in the opening.The opening may be an uncased opening. An uncased opening eliminatescost associated with thermally cementing the heater to the formation,costs associated with a casing, and/or costs of packing a heater withinan opening. In addition, heat transfer by radiation is typically moreefficient than by conduction, so the heaters may be operated at lowertemperatures in an open wellbore. Conductive heat transfer duringinitial operation of a heat source may be enhanced by the addition of agas in the opening. The gas may be maintained at a pressure up to about27 bars absolute. The gas may include, but is not limited to, carbondioxide and/or helium. An insulated conductor heater in an open wellboremay advantageously be free to expand or contract to accommodate thermalexpansion and contraction. An insulated conductor heater mayadvantageously be removable from an open wellbore.

[0960] In an embodiment, an insulated conductor heater may be installedor removed using a spooling assembly. More than one spooling assemblymay be used to install both the insulated conductor and a support membersimultaneously. U.S. Pat. No. 4,572,299 issued to Van Egmond et al.,which is incorporated by reference as if fully set forth herein,describes spooling an electric heater into a well. Alternatively, thesupport member may be installed using a coiled tubing unit. The heatersmay be un-spooled and connected to the support as the support isinserted into the well. The electric heater and the support member maybe un-spooled from the spooling assemblies. Spacers may be coupled tothe support member and the heater along a length of the support member.Additional spooling assemblies may be used for additional electricheater elements.

[0961] In an in situ conversion process embodiment, a heater may beinstalled in a substantially horizontal wellbore. Installing a heater ina wellbore (whether vertical or horizontal) may include placing one ormore heaters (e.g., three mineral insulated conductor heaters) within aconduit. FIG. 64 depicts an embodiment of a portion of three insulatedconductor heaters 6232 placed within conduit 6234. Insulated conductorheaters 6232 may be spaced within conduit 6234 using spacers 6236 tolocate the insulated conductor heater within the conduit.

[0962] The conduit may be reeled onto a spool. The spool may be placedon a transporting platform such as a truck bed or other platform thatcan be transported to a site of a wellbore. The conduit may be unreeledfrom the spool at the wellbore and inserted into the wellbore to installthe heater within the wellbore. A welded cap may be placed at an end ofthe coiled conduit. The welded cap may be placed at an end of theconduit that enters the wellbore first. The conduit may allow easyinstallation of the heater into the wellbore. The conduit may alsoprovide support for the heater.

[0963] In some heat source embodiments, coiled tubing installation maybe used to install one or more wellbore elements placed in openings in aformation for an in situ conversion process. For example, a coiledconduit may be used to install other types of wells in a formation. Theother types of wells may be, but are not limited to, monitor wells,freeze wells or portions of freeze wells, dewatering wells or portionsof dewatering wells, outer casings, injection wells or portions ofinjection wells, production wells or portions of production wells, andheat sources or portions of heat sources. Installing one or morewellbore elements using a coiled conduit installation process may beless expensive and faster than using other installation processes.

[0964] Coiled tubing installation may reduce a number of welded and/orthreaded connections in a length of casing. Welds and/or threadedconnections in coiled tubing may be pre-tested for integrity (e.g., byhydraulic pressure testing). Coiled tubing is available from QualityTubing, Inc. (Houston, Tex.), Precision Tubing (Houston, Tex.), andother manufacturers. Coiled tubing may be available in many sizes anddifferent materials. Sizes of coiled tubing may range from about 2.5 cm(1 inch) to about 15 cm (6 inches). Coiled tubing may be available in avariety of different metals, including carbon steel. Coiled tubing maybe spooled on a large diameter reel. The reel may be carried on a coiledtubing unit. Suitable coiled tubing units are available from Halliburton(Duncan, Okla.), Fleet

[0965] Cementers, Inc. (Cisco, Tex.), and Coiled Tubing Solutions, Inc.(Eastland, Tex.). Coiled tubing may be unwound from the reel, passedthrough a straightener, and inserted into a wellbore. A wellcap may beattached (e.g., welded) to an end of the coiled tubing before insertingthe coiling tubing into a well. After insertion, the coiled tubing maybe cut from the coiled tubing on the reel.

[0966] In some embodiments, coiled tubing may be inserted into apreviously cased opening, e.g., if a well is to be used later as aheater well, production well, or monitoring well. Alternately, coiledtubing installed within a wellbore can later be perforated (e.g., with aperforation gun) and used as a production conduit.

[0967] Embodiments of heat sources, production wells, and/or freezewells may be installed in a formation using coiled tubing installation.Some embodiments of heat sources, production wells, and freeze wellsinclude an element placed within an outer casing. For example, aconductor-in-conduit heater may include an outer conduit with an innerconduit placed in the outer conduit. A production well may include aheater element or heater elements placed within a casing to inhibitcondensation and refluxing of vapor phase production fluids. A freezewell may include a refrigerant input line placed within a casing, or arefrigeration inlet and outlet line. Spacers may be spaced along alength of an element, or elements, positioned within a casing to inhibitthe element, or elements, from contacting walls of the casing.

[0968] In some embodiments of heat sources, production wells, and freezewells, casings may be installed using coiled tube installation. Elementsmay be placed within the casing after the casing is placed in theformation for heat sources or wells that include elements within thecasings. In some embodiments, sections of casings may be threaded and/orwelded and inserted into a wellbore using a drilling rig or workoverrig. In some embodiments of heat sources, production wells, and freezewells, elements may be placed within the casing before the casing iswound onto a reel.

[0969] Some wells may have sealed casings that inhibit fluid flow fromthe formation into the casing. Sealed casings also inhibit fluid flowfrom the casing into the formation. Some casings may be perforated,screened or have other types of openings that allow fluid to pass intothe casing from the formation, or fluid from the casing to pass into theformation. In some embodiments, portions of wells are open wellboresthat do not include casings.

[0970] In an embodiment, the support member may be installed usingstandard oil field operations and welding different sections of support.Welding may be done by using orbital welding. For example, a firstsection of the support member may be disposed into the well. A secondsection (e.g., of substantially similar length) may be coupled to thefirst section in the well. The second section may be coupled by weldingthe second section to the first section. An orbital welder disposed atthe wellhead may weld the second section to the first section. Thisprocess may be repeated with subsequent sections coupled to previoussections until a support of desired length is within the well.

[0971]FIG. 62 illustrates a cross-sectional view of one embodiment of awellhead coupled to overburden casing 541. Flange 590 c may be coupledto, or may be a part of, wellhead 590. Flange 590 c may be formed ofcarbon steel, stainless steel, or any other material. Flange 590 c maybe sealed with o-ring 590 f, or any other sealing mechanism. Supportmember 564 may be coupled to flange 590 c. Support member 564 maysupport one or more insulated conductor heaters. In an embodiment,support member 564 is sealed in flange 590 c by welds 590 h.

[0972] Power conductor 590 a may be coupled to a lead-in cable and/or aninsulated conductor heater. Power conductor 590 a may provide electricalenergy to the insulated conductor heater. Power conductor 590 a may besealed in sealing flange 590 d. Sealing flange 590 d may be sealed bycompression seals or o-rings 590 e. Power conductor 590 a may be coupledto support member 564 with band 590 i. Band 590 i may include a rigidand corrosion resistant material such as stainless steel. Wellhead 590may be sealed with weld 590 h such that fluids are inhibited fromescaping the formation through wellhead 590. Lift bolt 590 j may liftwellhead 590 and support member 564.

[0973] Thermocouple 590 g may be provided through flange 590 c.Thermocouple 590 g may measure a temperature on or proximate supportmember 564 within the heated portion of the well. Compression fittings590 k may serve to seal power cable 590 a. Compression fittings 5901 mayserve to seal thermocouple 590 g. The compression fittings may inhibitfluids from escaping the formation. Wellhead 590 may also include apressure control valve. The pressure control valve may control pressurewithin an opening in which support member 564 is disposed.

[0974] In a heat source embodiment, a control system may controlelectrical power supplied to an insulated conductor heater. Powersupplied to the insulated conductor heater may be controlled with anyappropriate type of controller. For alternating current, the controllermay be, but is not limited to, a tapped transformer or a zero crossoverelectric heater firing SCR (silicon controlled rectifier) controller.Zero crossover electric heater firing control may be achieved byallowing full supply voltage to the insulated conductor heater to passthrough the insulated conductor heater for a specific number of cycles,starting at the “crossover,” where an instantaneous voltage may be zero,continuing for a specific number of complete cycles, and discontinuingwhen the instantaneous voltage again crosses zero. A specific number ofcycles may be blocked, allowing control of the heat output by theinsulated conductor heater. For example, the control system may bearranged to block fifteen and/or twenty cycles out of each sixty cyclesthat are supplied by a standard 60 Hz alternating current power supply.Zero crossover firing control may be advantageously used with materialshaving low temperature coefficient materials. Zero crossover firingcontrol may inhibit current spikes from occurring in an insulatedconductor heater.

[0975]FIG. 63 illustrates an embodiment of a conductor-in-conduit heaterthat may heat a relatively permeable formation. Conductor 580 may bedisposed in conduit 582. Conductor 580 may be a rod or conduit ofelectrically conductive material. Low resistance sections 584 may bepresent at both ends of conductor 580 to generate less heating in thesesections. Low resistance section 584 may be formed by having a greatercross-sectional area of conductor 580 in that section, or the sectionsmay be made of material having less resistance. In certain embodiments,low resistance section 584 includes a low resistance conductor coupledto conductor 580. In some heat source embodiments, conductors 580 may be316, 304, or 310 stainless steel rods with diameters of approximately2.8 cm. In some heat source embodiments, conductors are 316, 304, or 310stainless steel pipes with diameters of approximately 2.5 cm. Larger orsmaller diameters of rods or pipes may be used to achieve desiredheating of a formation. The diameter and/or wall thickness of conductor580 may be varied along a length of the conductor to establish differentheating rates at various portions of the conductor. Conduit 582 may bemade of an electrically conductive material. For example, conduit 582may be a 7.6 cm, schedule 40 pipe made of 316, 304, or 310 stainlesssteel.

[0976] Conduit 582 may be disposed in opening 514 in hydrocarbon layer516. Opening 514 has a diameter able to accommodate conduit 582. Adiameter of the opening may be from about 10 cm to about 13 cm. Largeror smaller diameter openings may be used to accommodate particularconduits or designs.

[0977] Conductor 580 may be centered in conduit 582 by centralizer 581.Centralizer 581 may electrically isolate conductor 580 from conduit 582.Centralizer 581 may inhibit movement and properly locate conductor 580within conduit 582. Centralizer 581 may be made of a ceramic material ora combination of ceramic and metallic materials. Centralizers 581 mayinhibit deformation of conductor 580 in conduit 582. Centralizer 581 maybe spaced at intervals between approximately 0.5 m and approximately 3 malong conductor 580. FIGS. 65, 66, and 67 depict embodiments ofcentralizers 581.

[0978] A second low resistance section 584 of conductor 580 may coupleconductor 580 to wellhead 690, as depicted in FIG. 63. Electricalcurrent may be applied to conductor 580 from power cable 585 through lowresistance section 584 of conductor 580. Electrical current may passfrom conductor 580 through sliding connector 583 to conduit 582. Conduit582 may be electrically insulated from overburden casing 541 and fromwellhead 690 to return electrical current to power cable 585. H eat maybe generated in conductor 580 and conduit 582. The generated heat mayradiate within conduit 582 and opening 514 to heat at least a portion ofhydrocarbon layer 516. As an example, a voltage of about 330 volts and acurrent of about 795 amps may be supplied to conductor 580 and conduit582 in a 229 m (750 ft) heated section to generate about 1150watts/meter of conductor 580 and conduit 582.

[0979] Overburden conduit 541 may be disposed in overburden 540.Overburden conduit 541 may, in some embodiments, be surrounded bymaterials that inhibit heating of overburden 540. Low resistance section584 of conductor 580 may be placed in overburden conduit 541. Lowresistance section 584 of conductor 580 may be made of, for example,carbon steel. Low resistance section 584 may have a diameter betweenabout 2 cm to about 5 cm or, for example, a diameter of about 4 cm. Lowresistance section 584 of conductor 580 may be centralized withinoverburden conduit 541 using centralizers 581. Centralizers 581 may bespaced at intervals of approximately 6 m to approximately 12 m or, forexample, approximately 9 m along low resistance section 584 of conductor580. In a heat source embodiment, low resistance section 584 ofconductor 580 is coupled to conductor 580 by a weld or welds. In otherheat source embodiments, low resistance sections may be threaded,threaded and welded, or otherwise coupled to the conductor. Lowresistance section 584 may generate little and/or no heat in overburdenconduit 541. Packing material 542 may be placed between overburdencasing 541 and opening 514. Packing material 542 may inhibit fluid fromflowing from opening 514 to surface 550.

[0980] In a heat source embodiment, overburden conduit is a 7.6 cmschedule 40 carbon steel pipe. In some embodiments, the overburdenconduit may be cemented in the overburden. Cement 544 may be slag orsilica flour or a mixture thereof (e.g., about 1.58 grams per cubiccentimeter slag/silica flour). Cement 544 may extend radially a width ofabout 5 cm to about 25 cm. Cement 544 may also be made of materialdesigned to inhibit flow of heat into overburden 540. In other heatsource embodiments, overburden may not be cemented into the formation.Having an uncemented overburden casing may facilitate removal of conduit582 if the need for removal should arise.

[0981] Surface conductor 545 may couple to wellhead 690. Surfaceconductor 545 may have a diameter of about 10 cm to about 30 cm or, incertain embodiments, a diameter of about 22 cm. Electrically insulatingsealing flanges may mechanically couple low resistance section 584 ofconductor 580 to wellhead 690 and to electrically couple low resistancesection 584 to power cable 585. The electrically insulating sealingflanges may couple power cable 585 to wellhead 690. For example, lead-inconductor 585 may include a copper cable, wire, or other elongatedmember. Lead-in conductor 585 may include any material having asubstantially low resistance. The lead-in conductor may be clamped tothe bottom of the low resistance conductor to make electrical contact.

[0982] In an embodiment, heat may be generated in or by conduit 582.About 10% to about 30%, or, for example, about 20%, of the total heatgenerated by the heater may be generated in or by conduit 582. Bothconductor 580 and conduit 582 may be made of stainless steel. Dimensionsof conductor 580 and conduit 582 may be chosen such that the conductorwill dissipate heat in a range from approximately 650 watts per meter to1650 watts per meter. A temperature in conduit 582 may be approximately480° C. to approximately 815° C., and a temperature in conductor 580 maybe approximately 500° C. to 840° C. Substantially uniform heating of arelatively permeable formation may be provided along a length of conduit582 greater than about 300 m or, even greater than about 600 m.

[0983]FIG. 68 depicts a cross-sectional representation of an embodimentof a removable conductor-in-conduit heat source. Conduit 582 may beplaced in opening 514 through overburden 540 such that a gap remainsbetween the conduit and overburden casing 541. Fluids may be removedfrom opening 514 through the gap between conduit 582 and overburdencasing 541. Fluids may be removed from the gap through conduit 5010.Conduit 582 and components of the heat source included within theconduit that are coupled to wellhead 690 may be removed from opening 514as a single unit. The heat source may be removed as a single unit to berepaired, replaced, and/or used in another portion of the formation.

[0984] In certain embodiments, portions of a conductor-in-conduit heatsource may be moved or removed to adjust a portion of the formation thatis heated by the heat source. For example, in a horizontal well theconductor-in-conduit heat source may be initially almost as long as theopening in the formation. As products are produced from the formation,the conductor-in-conduit heat source may be moved so that it is placedat location further from the end of the opening in the formation. Heatmay be applied to a different portion of the formation by adjusting thelocation of the heat source. In certain embodiments, an end of theheater may be coupled to a sealing mechanism (e.g., a packing mechanism,or a plugging mechanism) to seal off perforations in a liner or casing.The sealing mechanism may inhibit undesired fluid production fromportions of the heat source wellbore from which the conductor-in-conduitheat source has been removed.

[0985] As depicted in FIG. 69, sliding connector 583 may be coupled nearan end of conductor 580. Sliding connector 583 may be positioned near abottom end of conduit 582. Sliding connector 583 may electrically coupleconductor 580 to conduit 582. Sliding connector 583 may move during useto accommodate thermal expansion and/or contraction of conductor 580 andconduit 582 relative to each other. In some embodiments, slidingconnector 583 may be attached to low resistance section 584 of conductor580. The lower resistance of section 584 may allow the sliding connectorto be at a temperature that does not exceed about 90° C. Maintainingsliding connector 583 at a relatively low temperature may inhibitcorrosion of the sliding connector and promote good contact between thesliding connector and conduit 582.

[0986] Sliding connector 583 may include scraper 593. Scraper 593 mayabut an inner surface of conduit 582 at point 595. Scraper 593 mayinclude any metal or electrically conducting material (e.g., steel orstainless steel). Centralizer 591 may couple to conductor 580. In someembodiments, sliding connector 583 may be positioned on low resistancesection 584 of conductor 580. Centralizer 591 may include anyelectrically conducting material (e.g., a metal or metal alloy). Springbow 592 may couple scraper 593 to centralizer 591. Spring bow 592 mayinclude any metal or electrically conducting material (e.g.,copper-beryllium alloy). In some embodiments, centralizer 591, springbow 592, and/or scraper 593 are welded together.

[0987] More than one sliding connector 583 may be used for redundancyand to reduce the current through each scraper 593. In addition, athickness of conduit 582 may be increased for a length adjacent tosliding connector 583 to reduce heat generated in that portion ofconduit. The length of conduit 582 with increased thickness may be, forexample, approximately 6 m.

[0988]FIG. 70 illustrates an embodiment of a wellhead. Wellhead 690 maybe coupled to electrical junction box 690 a by flange 690 n or any othersuitable mechanical device. Electrical junction box 690 a may controlpower (current and voltage) supplied to an electric heater. Power source690 t may be included in electrical junction box 690 a. In a heat sourceembodiment, the electric heater is a conductor-in-conduit heater. Flange690 n may include stainless steel or any other suitable sealingmaterial. Conductor 690 b may electrically couple conduit 582 to powersource 690 t. In some embodiments, power source 690 t may be locatedoutside wellhead 690 and the power source is coupled to the wellheadwith power cable 585, as shown in FIG. 63. Low resistance section 584may be coupled to power source 690 t. Compression seal 690 c may sealconductor 690 b at an inner surface of electrical junction box 690 a.

[0989] Flange 690 n may be sealed with metal o-ring 690 d. Conduit 690 fmay couple flange 690 n to flange 690 m. Flange 690 m may couple to anoverburden casing. Flange 690 m may be sealed with o-ring 690 g (e.g.,metal o-ring or steel o-ring). Low resistance section 584 of theconductor may couple to electrical junction box 690 a. Low resistancesection 584 may be passed through flange 690 n. Low resistance section584 may be sealed in flange 690 n with o-ring assembly 690 p. Assemblies690 p are designed to insulate low resistance section 584 from flange690 n and flange 690 m. Compression seal 690 c may be designed toelectrically insulate conductor 690 b from flange 690 n and junction box690 a. Centralizer 581 may couple to low resistance section 584.Thermocouples 690 i may be coupled to thermocouple flange 690 q withconnectors 690 h and wire 690 j. Thermocouples 690 i may be enclosed inan electrically insulated sheath (e.g., a metal sheath). Thermocouples690 i may be sealed in thermocouple flange 690 q with compression seals690 k. Thermocouples 690 i may be used to monitor temperatures in theheated portion downhole. In some embodiments, fluids (e.g., vapors) maybe removed through wellhead 690. For example, fluids from outsideconduit 582 may be removed through flange 690 r or fluids within theconduit may be removed through flange 690 s.

[0990]FIG. 71 illustrates an embodiment of a conductor-in-conduit heaterplaced substantially horizontally within hydrocarbon layer 516. Heatedsection 6011 may be placed substantially horizontally within hydrocarbonlayer 516. Heater casing 6014 may be placed within hydrocarbon layer516. Heater casing 6014 may be formed of a corrosion resistant,relatively rigid material (e.g., 304 stainless steel). Heater casing6014 may be coupled to overburden casing 541. Overburden casing 541 mayinclude materials such as carbon steel. In an embodiment, overburdencasing 541 and heater casing 6014 have a diameter of about 15 cm.Expansion mechanism 6012 may be placed at an end of heater casing 6014to accommodate thermal expansion of the conduit during heating and/orcooling.

[0991] To install heater casing 6014 substantially horizontally withinhydrocarbon layer 516, overburden casing 541 may bend from a verticaldirection in overburden 540 into a horizontal direction withinhydrocarbon layer 516. A curved wellbore may be formed during drillingof the wellbore in the formation. Heater casing 6014 and overburdencasing 541 may be installed in the curved wellbore. A radius ofcurvature of the curved wellbore may be determined by properties ofdrilling in the overburden and the formation. For example, the radius ofcurvature may be about 200 m from point 6015 to point 6016.

[0992] Conduit 582 may be placed within heater casing 6014. In someembodiments, conduit 582 may be made of a corrosion resistant metal(e.g., 304 stainless steel). Conduit may be heated to a hightemperature. Conduit 582 may also be exposed to hot formation fluids.Conduit 582 may be treated to have a high emissivity. Conduit 582 mayhave upper section 6002. In some embodiments, upper section 6002 may bemade of a less corrosion resistant metal than other portions of conduit582 (e.g., carbon steel). A large portion of upper section 6002 may bepositioned in overburden 540 of the formation. Upper section 6002 maynot be exposed to temperatures as high as the temperatures of conduit582. In an embodiment, conduit 582 and upper section 6002 have adiameter of about 7.6 cm.

[0993] Conductor 580 may be placed in conduit 582. A portion of theconduit placed adjacent to conduit may be made of a metal that hasdesired electrical properties, emissivity, creep resistance andcorrosion resistance at high temperatures. Conductor may include, but isnot limited to, 310 stainless steel, 304 stainless steel, 316 stainlesssteel, 347 stainless steel, and/or other steel or non-steel alloys.Conductor 580 may have a diameter of about 3 cm, however, a diameter ofconductor 580 may vary depending on, but not limited to, heatingrequirements and power requirements. Conductor 580 may be located inconduit 582 using one or more centralizers 581. Centralizers 581 may beceramic or a combination of metal and ceramic. Centralizers 581 mayinhibit conductor from contacting conduit 582. In some embodiments,centralizers 581 may be coupled to conductor 580. In other embodiments,centralizers 581 may be coupled to conduit 582. Conductor 580 may beelectrically coupled to conduit 582 using sliding connector 583.

[0994] Conductor 580 may be coupled to transition conductor 6010.Transition conductor 6010 may be used as an electrical transitionbetween lead-in conductor 6004 and conductor 580. In an embodiment,transition conductor 6010 may be carbon steel. Transition conductor 6010may be coupled to lead-in conductor 6004 with electrical connector 6008.FIG. 72 illustrates an enlarged view of an embodiment of a junction oftransition conductor 6010, electrical connector 6008, insulator 6006,and lead-in conductor 6004. Lead-in conductor 6004 may include one ormore conductors (e.g., three conductors). In certain embodiments, theone or more conductors may be insulated copper conductors (e.g.,rubber-insulated copper cable). In some embodiments, the one or moreconductors may be insulated or un-insulated stranded copper cable. Asshown in FIG. 72, insulator 6006 may be placed inside lead-in conductor6004. Insulator 6006 may include electrically insulating materials suchas fiberglass. Insulator 6006 may couple electrical connector 6008 toheater support 6000. In an embodiment, electrical current may flow froma power supply through lead-in conductor 6004, through transitionconductor 6010, into conductor 580, and return through conduit 582 andupper section 6002.

[0995] Referring to FIG. 71, heater support 6000 may include a supportthat is used to install heated section 6011 in hydrocarbon layer 516.For example, heater support 6000 may be a sucker rod that is insertedthrough overburden 540 from a ground surface. The sucker rod may includeone or more portions that can be coupled to each other at the surface asthe rod is inserted into the formation. In some embodiments, heatersupport 6000 is a single piece assembled in an assembly facility.Inserting heater support 6000 into the formation may push heated section6011 into the formation.

[0996] Overburden casing 541 may be supported within overburden 540using reinforcing material 544. Reinforcing material may include cement(e.g., Portland cement). Surface conductor 545 may enclose reinforcingmaterial 544 and overburden casing 541 in a portion of overburden 540proximate the ground surface. Surface conductor 545 may include asurface casing.

[0997]FIG. 73 illustrates a schematic of an alternate embodiment of aconductor-in-conduit heater placed substantially horizontally within aformation. In an embodiment, heater support 6000 may be a low resistanceconductor (e.g., low resistance section 584 as shown in FIG. 63). Heatersupport 6000 may include carbon steel or other electrically-conductingmaterials. Heater support 6000 may be electrically coupled to transitionconductor 6010 and conductor 580.

[0998] In some embodiments, a heat source may be placed within anuncased wellbore in a relatively permeable formation. FIG. 75illustrates a schematic of an embodiment of a conductor-in-conduitheater placed substantially horizontally within an uncased wellbore in aformation. Heated section 6011 may be placed within opening 514 inhydrocarbon layer 516. In certain embodiments, heater support 6000 maybe a low resistance conductor (e.g., low resistance section 584 as shownin FIG. 63). Heater support 6000 may be electrically coupled totransition conductor 6010 and conductor 580. FIG. 74 depicts analternate embodiment of the conductor-in-conduit heater shown in FIG.75. In certain embodiments, perforated casing 9636 may be placed inopening 514 as shown in FIG. 74. In some embodiments, centralizers 581may be used to support perforated casing 9636 within opening 514.

[0999] In certain heat source embodiments, a cladding section may becoupled to heater support 6000 and/or upper section 6002. FIG. 76depicts an embodiment of cladding section 9200 coupled to heater support6000. Cladding may also be coupled to an upper section of conduit 582.Cladding section 9200 may reduce the electrical resistance of heatersupport 6000 and/or the upper section of conduit 582. In an embodiment,cladding section 9200 is copper tubing coupled to the heater support andthe conduit.

[1000] In other heat source embodiments, heated section 6011, as shownin FIGS. 71, 73, and 75, may be placed in a wellbore with an orientationother than substantially horizontally in hydrocarbon layer 516. Forexample, heated section 6011 may be placed in hydrocarbon layer 516 atan angle of about 45° or substantially vertically in the formation. Inaddition, elements of the heat source placed in overburden 540 (e.g.,heater support 6000, overburden casing 541, upper section 6002, etc.)may have an orientation other than substantially vertical within theoverburden.

[1001] In certain heat source embodiments, the heat source may beremovably installed in a formation. Heater support 6000 may be used toinstall and/or remove the heat source, including heated section 6011,from the formation. The heat source may be removed to repair, replace,and/or use the heat source in a different wellbore. The heat source maybe reused in the same formation or in a different formation. In someembodiments, a heat source or a portion of a heat source may be spooledon coiled tubing rig and moved to another well location.

[1002] In some embodiments for heating a relatively permeable formation,more than one heater may be installed in a wellbore or heater well.Having more than one heater in a wellbore or heat source may provide theability to heat a selected portion or portions of a formation at adifferent rate than other portions of the formation. Having more thanone heater in a wellbore or heat source may provide a backup heat sourcein the wellbore or heat source should one or more of the heaters fail.Having more than one heater may allow a uniform temperature profile tobe established along a desired portion of the wellbore. Having more thanone heater may allow for rapid heating of a hydrocarbon layer or layersto a pyrolysis temperature from ambient temperature. The more than oneheater may include similar types of heaters or may include differenttypes of heaters. For example, the more than one heater may be a naturaldistributed combustor heater, an insulated conductor heater, aconductor-in-conduit heater, an elongated member heater, a downholecombustor (e.g., a downhole flameless combustor or a downholecombustor), etc.

[1003] In an in situ conversion process embodiment, a first heater in awellbore may be used to selectively heat a first portion of a formationand a second heater may be used to selectively heat a second portion ofthe formation. The first heater and the second heater may beindependently controlled. For example, heat provided by a first heatercan be controlled separately from heat provided by a second heater. Asanother example, electrical power supplied to a first electric heatermay be controlled independently of electrical power supplied to a secondelectric heater. The first portion and the second portion may be locatedat different heights or levels within a wellbore, either vertically oralong a face of the wellbore. The first portion and the second portionmay be separated by a third, or separate, portion of a formation. Thethird portion may contain hydrocarbons or may be a non-hydrocarboncontaining portion of the formation. For example, the third portion mayinclude rock or similar non-hydrocarbon containing materials. The thirdportion may be heated or unheated. In some embodiments, heat used toheat the first and second portions may be used to heat the thirdportion. Heat provided to the first and second portions maysubstantially uniformly heat the first, second, and third portions.

[1004]FIG. 65 illustrates a perspective view of an embodiment of acentralizer in conduit 582. Electrical insulator 581 a may be disposedon conductor 580. Insulator 581 a may be made of aluminum oxide or otherelectrically insulating material that has a high working temperaturelimit. Neck portion 581 j may be a bushing which has an inside diameterthat allows conductor 580 to pass through the bushing. Neck portion 581j may include electrically-insulative materials such as metal oxides andceramics (e.g., aluminum oxide). Insulator 581 a and neck portion 581 jmay be obtainable from manufacturers such as CoorsTek (Golden, Colo.) orNorton Ceramics (United Kingdom). In an embodiment, insulator 581 aand/or neck portion 581 j are made from 99% or greater purity machinablealuminum oxide. In certain embodiments, ceramic portions of a heatsource may be surface glazed. Surface glazing ceramic may seal theceramic from contamination from dirt and/or moisture. High temperaturesurface glazing of ceramics may be done by companies such as NGK-LockeInc. (Baltimore, Md.) or Johannes Gebhart (Germany).

[1005] A location of insulator 581 a on conductor 580 may be maintainedby disc 581 d. Disc 581 d may be welded to conductor 580. Spring bow 581c may be coupled to insulator 581 a by disc 581 b. Spring bow 581 c anddisc 581 b may be made of metals such as 310 stainless steel and/or anyother thermally conducting material that may be used at relatively hightemperatures. Spring bow 581 c may reduce the stress on ceramic portionsof the centralizer during installation or removal of the heater, and/orduring use of the heater. Reducing the stress on ceramic portions of thecentralizer during installation or removal may increase an operationallifetime of the heater. In some heat source embodiments, centralizer 581may have an opening that fits over an end of conductor. In otherembodiments, centralizer 581 may be assembled from two or more piecesaround a portion of conductor 580. The pieces may be coupled toconductor 580 by fastening device 581 e. Fastening device 581 e may bemade of any material that can be used at relatively high temperatures(e.g., steel).

[1006]FIG. 66 depicts a representation of an embodiment of centralizer581 disposed on conductor 580. Discs 581 d may maintain positions ofcentralizer 581 relative to conductor 580. Discs 581 d may be metaldiscs welded to conductor 580. Discs 581 d may be tack-welded toconductor 580. FIG. 67 depicts a top view representation of acentralizer embodiment. Centralizer 581 may be made of any suitableelectrically insulating material able to withstand high voltage at hightemperatures. Examples of such materials include, but are not limitedto, aluminum oxide and/or Macor. Centralizer 581 may electricallyinsulate conductor 580 from conduit 582.

[1007]FIG. 77 illustrates a cross-sectional representation of anembodiment of a centralizer placed on a conductor. FIG. 78 depicts aportion of an embodiment of a conductor-in-conduit heat source with acutout view showing a centralizer on the conductor. Centralizer 581 maybe used in a conductor-in-conduit heat source. Centralizer 581 may beused to maintain a location of conductor 580 within conduit 582.Centralizer 581 may include electrically-insulating materials such asceramics (e.g., alumina and zirconia). As shown in FIG. 77, centralizer581 may have at least one recess 581 i. Recess 581 i may be, forexample, an indentation or notch in centralizer 581 or a recess left bya portion removed from the centralizer. A cross-sectional shape ofrecess 581 i may be a rectangular shape or any other geometrical shape.In certain embodiments, recess 581 i has a shape that allows protrusion581 g to reside within the recess. Recess 581 i may be formed such thatthe recess will be placed at a junction of centralizer 581 and conductor580. In one embodiment, recess 581 i is formed at a bottom ofcentralizer 581.

[1008] At least one protrusion 581 g may be formed on conductor 580.Protrusion 581 g may be welded to conductor 580. In some embodiments,protrusion 581 g is a weld bead formed on conductor 580. Protrusion 581g may include electrically-conductive materials such as steel (e.g.,stainless steel). In certain embodiments, protrusion 581 g may includeone or more protrusions formed around the circumference of conductor580. Protrusion 581 g may be used to maintain a location of centralizer581 on conductor 580. For example, protrusion 581 g may inhibit downwardmovement of centralizer 581 along conductor 580. In some embodiments, atleast one additional recess 581 i and at least one additional protrusion581 g may be placed at a top of centralizer 581 to inhibit upwardmovement of the centralizer along conduit 580.

[1009] In an embodiment, electrically-insulating material 581 h isplaced over protrusion 581 g and recess 581 i. Electrically-insulatingmaterial 581 h may cover recess 581 i such that protrusion 581 g isenclosed within the recess and the electrically-insulating material. Insome embodiments, electrically-insulating material 581 h may partiallycover recess 581 i. Protrusion 581 g may be enclosed so that carbondeposition (i.e., coking) on protrusion 581 g during use is inhibited.Carbon may form electrically-conducting paths during use of conductor580 and conduit 582 to heat a formation. Electrically-insulatingmaterial 581 h may include materials such as, but not limited to, metaloxides and/or ceramics (e.g., alumina or zirconia). In some embodiments,electrically-insulating material 581 h is a thermally conductingmaterial. A thermal plasma spray process may be used to placeelectrically-insulating material 581 h over protrusion 581 g and recess581 i. The thermal plasma process may spray coat electrically-insulatingmaterial 581 h on protrusion 581 g and/or centralizer 581.

[1010] In an embodiment, centralizer 581 with recess 581 i, protrusion581 g, and electrically-insulating material 581 h are placed onconductor 580 within conduit 582 during installation of theconductor-in-conduit heat source in an opening in a formation. Inanother embodiment, centralizer 581 with recess 581 i, protrusion 581 g,and electrically-insulating material 581 h are placed on conductor 580within conduit 582 during assembling of the conductor-in-conduit heatsource. For example, an assembling process may include formingprotrusion 581 g on conductor 580, placing centralizer 581 with recess581 i on conductor 580, covering the protrusion and the recess withelectrically-insulating material 581 h, and placing the conductor withinconduit 582.

[1011]FIG. 79 depicts an alternate embodiment of centralizer 581. Neckportion 581 j may be coupled to centralizer 581. In certain embodiments,neck portion 581 j is an extended portion of centralizer 581. Protrusion581 g may be placed on conductor 580 to maintain a location ofcentralizer 581 and neck portion 581 j on the conductor. Neck portion581 j may be a bushing which has an inside diameter that allowsconductor 580 to pass through the bushing. Neck portion 581 j mayinclude electrically-insulative materials such as metal oxides andceramics (e.g., aluminum oxide). For example, neck portion 581 j may bea commercially available bushing from manufacturers such as BorgesTechnical Ceramics (Pennsburg, Pa.). In one embodiment, as shown in FIG.79, a first neck portion 581 j is coupled to an upper portion ofcentralizer 581 and a second neck portion 581 j is coupled to a lowerportion of centralizer 581.

[1012] Neck portion 581 j may extend between about 1 cm and about 5 cmfrom centralizer 581. In an embodiment, neck portion 581 j extends about2-3 cm from centralizer 581. Neck portion 581 j may extend a selecteddistance from centralizer 581 such that arcing (e.g., surface arcing) isinhibited. Neck portion 581 j may increase a path length for arcingbetween conductor 580 and conduit 582. A path for arcing betweenconductor 580 and conduit 582 may be formed by carbon deposition oncentralizer 581 and/or neck portion 581 j. Increasing the path lengthfor arcing between conductor 580 and conduit 582 may reduce thelikelihood of arcing between the conductor and the conduit. Anotheradvantage of increasing the path length for arcing between conductor 580and conduit 582 may be an increase in a maximum operating voltage of theconductor.

[1013] In an embodiment, neck portion 581 j also includes one or moregrooves 581 k. One or more grooves 581 k may further increase the pathlength for arcing between conductor 580 and conduit 582. In certainembodiments, conductor 580 and conduit 582 may be oriented substantiallyvertically within a formation. In such an embodiment, one or moregrooves 581 k may also inhibit deposition of conducting particles (e.g.,carbon particles or corrosion scale) along the length of neck portion581 j. Conducting particles may fall by gravity along a length ofconductor 580. One or more grooves 581 k may be oriented such thatfalling particles do not deposit into the one or more grooves.Inhibiting the deposition of conducting particles on neck portion 581 jmay inhibit formation of an arcing path between conductor 580 andconduit 582. In some embodiments, diameters of each of one or moregrooves 581 k may be varied. Varying the diameters of the grooves mayfurther inhibit the likelihood of arcing between conductor 580 andconduit 582.

[1014]FIG. 80 depicts an embodiment of centralizer 581. Centralizer 581may include two or more portions held together by fastening device 581e. Fastening device 581 e may be a clamp, bolt, snap-lock, or screw.FIGS. 81 and 82 depict top views of embodiments of centralizer 581placed on conduit 580. Centralizer 581 may include two portions. The twoportions may be coupled together to form a centralizer in a “clam shell”configuration. The two portions may have notches and recesses that areshaped to fit together as shown in either of FIGS. 81 and 82. In someembodiments, the two portions may have notches and recesses that aretapered so that the two portions tightly couple together. The twoportions may be slid together lengthwise along the notches and recesses.

[1015] In a heat source embodiment, an insulation layer may be placedbetween a conductor and a conduit. The insulation layer may be used toelectrically insulate the conductor from the conduit. The insulationlayer may also maintain a location of the conductor within the conduit.In some embodiments, the insulation layer may include a layer thatremains placed on and/or in the heat source after installation. Incertain embodiments, the insulation layer may be removed by heating theheat source to a selected temperature. The insulation layer may includeelectrically-insulating materials such as, but not limited to, metaloxides and/or ceramics. For example, the insulation layer may be Nextel™insulation obtainable from 3M Company (St. Paul, Minn.). An insulationlayer may also be used for installation of any other heat source (e.g.,insulated conductor heat source, natural distributed combustor, etc.).In an embodiment, the insulation layer is fastened to the conductor. Theinsulation layer may be fastened to the conductor with a hightemperature adhesive (e.g., a ceramic adhesive such as Cotronics 920alumina-based adhesive available from Cotronics Corporation (Brooklyn,N.Y.)).

[1016]FIG. 83 depicts a cross-sectional representation of an embodimentof a section of a conductor-in-conduit heat source with insulation layer9180. Insulation layer 9180 may be placed on conductor 580. Insulationlayer 9180 may be spiraled around conductor 580 as shown in FIG. 83. Inone embodiment, insulation layer 9180 is a single insulation layer woundaround the length of conductor 580. In some embodiments, insulationlayer 9180 may include one or more individual sections of insulationlayers wrapped around conductor 580. Conductor 580 may be placed inconduit 582 after insulation layer 9180 has been placed on theconductor. Insulation layer 9180 may electrically insulate conductor 580from conduit 582.

[1017] In an embodiment of a conductor-in-conduit heat source, a conduitmay be pressurized with a fluid to inhibit a large pressure differencebetween pressure in the conduit and pressure in the formation. Balancedpressure or a small pressure difference may inhibit deformation of theconduit during use. The fluid may increase conductive heat transfer fromthe conductor to the conduit. The fluid may include, but is not limitedto, a gas such as helium, nitrogen, air, or mixtures thereof. The fluidmay inhibit arcing between the conductor and the conduit. If air and/orair mixtures are used to pressurize the conduit, the air and/or airmixtures may react with materials of the conductor and the conduit toform an oxide layer on a surface of the conductor and/or an oxide layeron an inner surface of the conduit. The oxide layer may inhibit arcing.The oxide layer may make the conductor and/or the conduit more resistantto corrosion.

[1018] Reducing the amount of heat losses to an overburden of aformation may increase an efficiency of a heat source. The efficiency ofthe heat source may be determined by the energy transferred into theformation through the heat source as a fraction of the energy input intothe heat source. In other words, the efficiency of the heat source maybe a function of energy that actually heats a desired portion of theformation divided by the electrical power (or other input power)provided to the heat source. To increase the amount of energy actuallytransferred to the formation, heating losses to the overburden may bereduced. Heating losses in the overburden may be reduced for electricalheat sources by the use of relatively low resistance conductors in theoverburden that couple a power supply to the heat source. Alternatingelectrical current flowing through certain conductors (e.g., carbonsteel conductors) tends to flow along the skin of the conductors. Thisskin depth effect may increase the resistance heating at the outersurface of the conductor (i.e., the current flows through only a smallportion of the available metal) and, thus increase heating of theoverburden. Electrically conductive casings, coatings, wiring, and/orcladdings may be used to reduce the electrical resistance of a conductorused in the overburden. Reducing the electrical resistance of theconductor in the overburden may reduce electricity losses to heating theconduit in the overburden portion and thereby increase the availableelectricity for resistive heating in portions of the conductor below theoverburden.

[1019] As shown in FIG. 63, low resistance section 584 may be coupled toconductor 580. Low resistance section 584 may be placed in overburden540. Low resistance section 584 may be, for example, a carbon steelconductor. Carbon steel may be used to provide mechanical strength forthe heat source in overburden 540. In an embodiment, an electricallyconductive coating may be coated on low resistance section 584 tofurther reduce an electrical resistance of the low resistance conductor.In some embodiments, the electrically conductive coating may be coatedon low resistance section 584 during assembly of the heat source. Inother embodiments, the electrically conductive coating may be coated onlow resistance section 584 after installation of the heat source inopening 514.

[1020] In some embodiments, the electrically conductive coating may besprayed on low resistance section 584. For example, the electricallyconductive coating may be a sprayed on thermal plasma coating. Theelectrically conductive coating may include conductive materials suchas, but not limited to, aluminum or copper. The electrically conductivecoating may include other conductive materials that can be thermalplasma sprayed. In certain embodiments, the electrically conductivecoating may be coated on low resistance section 584 such that theresistance of the low resistance conductor is reduced by a factor ofgreater than about 2. In some embodiments, the resistance is lowered bya factor of greater than about 4 or about 5. The electrically conductivecoating may have a thickness of between 0.1 mm and 0.8 mm. In anembodiment, the electrically conductive coating may have a thickness ofabout 0.25 mm. The electrically conductive coating may be coated on lowresistance conductors used with other types of heat sources such as, forexample, insulated conductor heat sources, elongated member heatsources, etc.

[1021] In another embodiment, a cladding may be coupled to lowresistance section 584 to reduce the electrical resistance in overburden540. FIG. 84 depicts a cross-sectional view of a portion of claddingsection 9200 of conductor-in-conduit heater. Cladding section 9200 maybe coupled to the outer surface of low resistance section 584. Claddingsections 9200 may also be coupled to an inner surface of conduit 582. Incertain embodiments, cladding sections may be coupled to inner surfaceof low resistance section 584 and/or outer surface of conduit 582. Insome embodiments, low resistance section 584 may include one or moresections of individual low resistance sections 584 coupled together.Conduit 582 may include one or more sections of individual conduits 582coupled together.

[1022] Individual cladding sections 9200 may be coupled to eachindividual low resistance section 584 and/or conduit 582, as shown inFIG. 84. A gap may remain between each cladding section 9200. The gapmay be at a location of a coupling between low resistance sections 584and/or conduits 582. For example, the gap maybe at a thread or weldjunction between low resistance sections 584 and/or conduits 582. Thegap may be less than about 4 cm in length. In certain embodiments, thegap may be less than about 5 cm in length or less than 6 cm in length.

[1023] Cladding section 9200 may be a conduit (or tubing) of relativelyelectrically conductive material. Cladding section 9200 may be a conduitthat tightly fits against a surface of low resistance section 584 and/orconduit 582. Cladding section 9200 may include non-ferromagnetic metalsthat have a relatively high electrical conductivity. For example,cladding section 9200 may include copper, aluminum, brass, bronze, orcombinations thereof. Cladding section 9200 may have a thickness betweenabout 0.2 cm and about 1 cm. In some embodiments, low resistance section584 has an outside diameter of about 2.5 cm and conduit 582 has aninside diameter of about 7.3 cm. In an embodiment, cladding section 9200coupled to low resistance section 584 is copper tubing with a thicknessof about 0.32 cm (about {fraction (1/8)} inch) and an inside diameter ofabout 2.5 cm. In an embodiment, cladding section 9200 coupled to conduit582 is copper tubing with a thickness of about 0.32 cm (about {fraction(1/8)} inch) and an outside diameter of about 7.3 cm. In certainembodiments, cladding section 9200 has a thickness between about 0.20 cmand about 1.2 cm.

[1024] In certain embodiments, cladding section 9200 is brazed to lowresistance section 584 and/or conduit 582. In other embodiments,cladding section 9200 may be welded to low resistance section 584 and/orconduit 582. In one embodiment, cladding section 9200 is Everdur®(silicon bronze) welded to low resistance section 584 and/or conduit582. Cladding section 9200 may be brazed or welded to low resistancesection 584 and/or conduit 582 depending on the types of materials usedin the cladding section, the low resistance conductor, and the conduit.For example, cladding section 9200 may include copper that is Everdur®welded to low resistance section 584, which includes carbon steel. Insome embodiments, cladding section 9200 may be pre-oxidized to inhibitcorrosion of the cladding section during use.

[1025] Using cladding section 9200 coupled to low resistance section 584and/or conduit 582 may inhibit a significant temperature rise in theoverburden of a formation during use of the heat source (i.e., reduceheat losses to the overburden). For example, using a copper claddingsection of about 0.3 cm thickness may decrease the electrical resistanceof a carbon steel low resistance conductor by a factor of about 20. Thelowered resistance in the overburden section of the heat source mayprovide a relatively small temperature increase adjacent to the wellborein the overburden of the formation. For example, supplying a current ofabout 500 A into an approximately 1.9 cm diameter low resistanceconductor (schedule 40 carbon steel pipe) with a copper cladding ofabout 0.3 cm thickness produces a maximum temperature of about 93° C. atthe low resistance conductor. This relatively low temperature in the lowresistance conductor may transfer relatively little heat to theformation. For a fixed voltage at the power source, lowering theresistance of the low resistance conductor may increase the transfer ofpower into the heated section of the heat source (e.g., conductor 580).For example, a 600 volt power supply may be used to supply power to aheat source through about a 300 m overburden and into about a 260 mheated section. This configuration may supply about 980 watts per meterto the heated section. Using a copper cladding section of about 0.3 cmthickness with a carbon steel low resistance conductor may increase thetransfer of power into the heated section by up to about 15% compared tousing the carbon steel low resistance conductor only.

[1026] In some embodiments, cladding section 9200 may be coupled toconductor 580 and/or conduit 582 by a “tight fit tubing” (TFT) method.TFT is commercially available from vendors such as Kuroki (Japan) orKarasaki Steel (Japan). The TFT method includes cryogenically cooling aninner pipe or conduit, which is a tight fit to an outer pipe. The cooledinner pipe is inserted into the heated outer pipe or conduit. Theassembly is then allowed to return to an ambient temperature. In somecases, the inner pipe can be hydraulically expanded to bond tightly withthe outer pipe.

[1027] Another method for coupling a cladding section to a conductor ora conduit may include an explosive cladding method. In explosivecladding, an inner pipe is slid into an outer pipe. Primer cord or othertype of explosive charge may be set off inside the inner pipe. Theexplosive blast may bond the inner pipe to the outer pipe.

[1028] Electromagnetically formed cladding may also be used for claddingsection 9200. An inner pipe and an outer pipe may be placed in a waterbath. Electrodes attached to the inner pipe and the outer pipe may beused to create a high potential between the inner pipe and the outerpipe. The potential may cause sudden formation of bubbles in the baththat bond the inner pipe to the outer pipe.

[1029] In another embodiment, cladding section 9200 may be arc welded toa conductor or conduit. For example, copper may be arc deposited and/orwelded to a stainless steel pipe or tube.

[1030] In some embodiments, cladding section 9200 may be formed withplasma powder welding (PPW). PPW formed material may be obtained fromDaido Steel Co. (Japan). In PPW, copper powder is heated to form aplasma. The hot plasma may be moved along the length of a tube (e.g., astainless steel tube) to deposit the copper and form the coppercladding.

[1031] Cladding section 9200 may also be formed by billet co-extrusion.A large piece of cladding material may be extruded along a pipe to forma desired length of cladding along the pipe.

[1032] In certain embodiments, forge welding (e.g., shielded active gaswelding) may be used to form claddings section 9200 on a conductorand/or conduit. Forge welding may be used to form a uniform weld throughthe cladding section and the conductor or conduit.

[1033] Another method is to start with strips of copper and carbon steelthat are bonded to together by tack welding or another suitable method.The composite strip is drawn through a shaping unit to form acylindrically shaped tube. The cylindrically shaped tube is seam weldedlongitudinally. The resulting tube may be coiled onto a spool.

[1034] Another possible embodiment for reducing the electricalresistance of the conductor in the overburden is to form low resistancesection 584 from low resistance metals (e.g., metals that are used incladding section 9200). A polymer coating may be placed on some of thesemetals to inhibit corrosion of the metals (e.g., to inhibit corrosion ofcopper or aluminum by hydrogen sulfide).

[1035] Increasing the emissivity of a conductive heat source mayincrease the efficiency at which heat is transferred to a formation. Anemissivity of a surface affects the amount of radiative heat emittedfrom the surface and the amount of radiative heat absorbed by thesurface. In general, the higher the emissivity a surface has, thegreater the radiation from the surface or the absorption of heat by thesurface. Thus, increasing the emissivity of a surface increases theefficiency of heat transfer because of the increased radiation of energyfrom the surface into the surroundings. For example, increasing theemissivity of a conductor in a conductor-in-conduit heat source mayincrease the efficiency at which heat is transferred to the conduit, asshown by the following equation: $\begin{matrix}{{\overset{.}{Q} = \frac{2\pi \quad r_{1}{\sigma \left( {T_{1}^{4} - T_{2}^{4}} \right)}}{\frac{1}{ɛ_{1}} + {\left( \frac{r_{1}}{r_{2}} \right)\left( {\frac{1}{ɛ_{2}} - 1} \right)}}};} & (18)\end{matrix}$

[1036] where, {dot over (Q)} is the rate of heat transfer between acylindrical conductor and a conduit, r₁ is the radius of the conductor,r₂ is the radius of the conduit, T₁ is the temperature at the conductor,T₂ is the temperature at the conduit, a is the Stefan-Boltzmann constant(5.670×10⁻⁸ J·K⁻⁴·m⁻²·s⁻¹), ε₁ is the emissivity of the conductor, andε₂ is the emissivity of the conduit. According to EQN. 18, increasingthe emissivity of the conductor increases the heat transfer between theconductor and the conduit. Accordingly, for a constant heat transferrate, increasing the emissivity of the conductor decreases thetemperature difference between the conductor and the conduit (i.e.,increases the temperature of the conduit for a given conductortemperature). Increasing the temperature of the conduit increases theamount of heat transfer to the formation.

[1037] In an embodiment, a conductor and/or conduit may be treated toincrease the emissivity of the conductor and/or conduit materials.Treating the conductor and/or conduit may include roughening a surfaceof the conductor or conduit and/or oxidizing the conductor or conduit.In some embodiments, a conductor and/or conduit may be roughened and/oroxidized prior to assembly of a heat source. In some embodiments, aconductor and/or conduit may be roughened and/or oxidized after assemblyand/or installation into a formation (e.g., an oxidizing fluid may beintroduced into an annular space between the conductor and the conduitwhen heating a portion of the formation to pyrolysis temperature so thatthe heat generated in the conductor oxidizes the conductor and theconduit). The treatment method may be used to treat inner surfacesand/or outer surfaces, or portions thereof, of conductors or conduits.In certain embodiments, the outer surface of a conductor and the innersurface of a conduit are treated to increase the emissivities of theconductor and the conduit.

[1038] In an embodiment, surfaces of a conductor, or a portion of thesurface, may be roughened. The roughened surface of the conductor may bethe outer surface of the conductor. The surface of the conductor may beroughened by, but is not limited to being roughened by, sandblasting orbeadblasting the surface, peening the surface, emery grinding thesurface, or using an electrostatic discharge method on the surface. Forexample, the surface of the conductor may be sand blasted with fineparticles to roughen the surface. The conductor may also be treated bypre-oxidizing the surface of the conductor (i.e., heating the conductorto an oxidation temperature before use of the conductor). Pre-oxidizingthe surface of the conductor may include heating the conductor to atemperature between about 850° C. and about 950° C. The conductor may beheated in an oven or furnace. The conductor may be heated in anoxidizing atmosphere (e.g., an oven with a charge of an oxidizing fluidsuch as air). In an embodiment, a 304H stainless steel conductor isheated in a furnace at a temperature of about 870° C. for about 2 hours.If the surface of the 304H stainless steel conductor is roughened priorto heating the conductor in the furnace, the emissivity of the 304Hstainless steel conductor may be increased from about 0.5 to about 0.85.Increasing the emissivity of the conductor may reduce an operatingtemperature of the conductor. Operating the conductor at lowertemperatures may increase an operational lifetime of the conductor. Forexample, operating the conductor at lower temperatures may reduce creepand/or corrosion.

[1039] In some embodiments, applying a coating to a conductor or conduitmay increase the emissivity of a conductor or a conduit and increase theefficiency of heat transfer to the formation. An electrically insulatingand thermally conductive coating may be placed on a conductor and/orconduit. The electrically insulating coating may inhibit arcing betweenthe conductor and the conduit. Arcing between the conductor and theconduit may cause shorting between the conductor and the conduit. Arcingmay also produce hot spots and/or cold spots on either the conductor orthe conduit. In some embodiments, a coating or coatings on portions of aconduit and/or a conductor may increase emissivity, electricallyinsulate, and promote thermal conduction.

[1040] As shown in FIG. 63, conductor 580 and conduit 582 may be placedin opening 514 in hydrocarbon layer 516. In an embodiment, anelectrically insulative, thermally conductive coating is placed onconductor 580 and conduit 582 (e.g., on an outside surface of theconductor and an inside surface of the conduit). In some embodiments,the electrically insulative, thermally conductive coating is placed onconductor 580. In other embodiments, the electrically insulative,thermally conductive coating is placed on conduit 582. The electricallyinsulative, thermally conductive coating may electrically insulateconductor 580 from conduit 582. The electrically insulative, thermallyconductive coating may inhibit arcing between conductor 580 and conduit582. In certain embodiments, the electrically insulative, thermallyconductive coating maintains an emissivity of conductor 580 or conduit582 (i.e., inhibits the emissivity of the conductor or conduit fromdecreasing). In other embodiments, the electrically insulative,thermally conductive coating increases an emissivity of conductor 580and/or conduit 582. The electrically insulative, thermally conductivecoating may include, but is not limited to, oxides of silicon, aluminum,and zirconium, or combinations thereof. For example, silicon oxide maybe used to increase an emissivity of a conductor or conduit whilealuminum oxide may be used to provide better electrical insulation andthermal conductivity. Thus, a combination of silicon oxide and aluminumoxide may be used to increase emissivity while providing improvedelectrical insulation and thermal conductivity. In an embodiment,aluminum oxide is coated on conductor 580 to electrically insulate theconductor followed by a coating of silicon oxide to increase theemissivity of the conductor.

[1041] In an embodiment, the electrically insulative, thermallyconductive coating is sprayed on conductor 580 or conduit 582. Thecoating may be sprayed on during assembly of the conductor-in-conduitheat source. In some embodiments, the coating is sprayed on beforeassembling the conductor-in-conduit heat source. For example, thecoating may be sprayed on conductor 580 or conduit 582 by a manufacturerof the conductor or conduit. In certain embodiments, the coating issprayed on conductor 580 or conduit 582 before the conductor or conduitis coiled onto a spool for installation. In other embodiments, thecoating is sprayed on after installation of the conductor-in-conduitheat source.

[1042] In a heat source embodiment, a perforated conduit may be placedin the opening formed in the relatively permeable formation proximateand external to the conduit of a conductor-in-conduit heater. Theperforated conduit may remove fluids formed in an opening in theformation to reduce pressure adjacent to the heat source. A pressure maybe maintained in the opening such that deformation of the first conduitis inhibited. In some embodiments, the perforated conduit may be used tointroduce a fluid into the formation adjacent to the heat source. Forexample, in some embodiments, hydrogen gas may be injected into theformation adjacent to selected heat sources to increase a partialpressure of hydrogen during in situ conversion.

[1043]FIG. 85 illustrates an embodiment of a conductor-in-conduit heaterthat may heat a relatively permeable formation. Second conductor 586 maybe disposed in conduit 582 in addition to conductor 580. Secondconductor 586 may be coupled to conductor 580 using connector 587located near a lowermost surface of conduit 582. Second conductor 586may be a return path for the electrical current supplied to conductor580. For example, second conductor 586 may return electrical current towellhead 690 through low resistance second conductor 588 in overburdencasing 541. Second conductor 586 and conductor 580 may be formed ofelongated conductive material. Second conductor 586 and conductor 580may be a stainless steel rod having a diameter of approximately 2.4 cm.Connector 587 may be flexible. Conduit 582 may be electrically isolatedfrom conductor 580 and second conductor 586 using centralizers 581. Theuse of a second conductor may eliminate the need for a slidingconnector. The absence of a sliding connector may extend the life of theheater. The absence of a sliding connector may allow for isolation ofapplied power from hydrocarbon layer 516.

[1044] In a heat source embodiment that utilizes second conductor 586,conductor 580 and the second conductor may be coupled by a flexibleconnecting cable. The bottom of the first and second conductor may haveincreased thicknesses to create low resistance sections. The flexibleconnector may be made of stranded copper covered with rubber insulation.

[1045] In a heat source embodiment, a first conductor and a secondconductor may be coupled to a sliding connector within a conduit. Thesliding connector may include insulating material that inhibitselectrical coupling between the conductors and the conduit. The slidingconnector may accommodate thermal expansion and contraction of theconductors and conduit relative to each other. The sliding connector maybe coupled to low resistance sections of the conductors and/or to a lowtemperature portion of the conduit.

[1046] In a heat source embodiment, the conductor may be formed ofsections of various metals that are welded or otherwise joined together.The cross-sectional area of the various metals may be selected to allowthe resulting conductor to be long, to be creep resistant at highoperating temperatures, and/or to dissipate desired amounts of heat perunit length along the entire length of the conductor. For example, afirst section may be made of a creep resistant metal (such as, but notlimited to, Inconel 617 or HR120), and a second section of the conductormay be made of 304 stainless steel. The creep resistant first sectionmay help to support the second section. The cross-sectional area of thefirst section may be larger than the cross-sectional area of the secondsection. The larger cross-sectional area of the first section may allowfor greater strength of the first section. Higher resistivity propertiesof the first section may allow the first section to dissipate the sameamount of heat per unit length as the smaller cross-sectional areasecond section.

[1047] In some embodiments, the cross-sectional area and/or the metalused for a particular conduit section may be chosen so that a particularsection provides greater (or lesser) heat dissipation per unit lengththan an adjacent section. More heat may be provided near an interfacebetween a hydrocarbon layer and a non-hydrocarbon layer (e.g., theoverburden and the hydrocarbon layer and/or an underburden and thehydrocarbon layer) to counteract end effects and allow for more uniformheat dissipation into the relatively permeable formation.

[1048] In a heat source embodiment, a conduit may have a variable wallthickness. Wall thickness may be thickest adjacent to portions of theformation that do not need to be fully heated. Portions of formationthat do not need to be fully heated may include layers of formation thathave low grade, little, or no hydrocarbon material.

[1049] In an embodiment of heat sources placed in a formation, a firstconductor, a second conductor and a third conductor may be electricallycoupled in a 3-phase Y electrical configuration. Each of the conductorsmay be a part of a conductor-in-conduit heater. The conductor-in-conduitheaters may be located in separate wellbores within the formation. Theouter conduits may be electrically coupled together or conduits may beconnected to ground. The 3-phase Y electrical configuration may providea safer and more efficient method to heat a relatively permeableformation than using a single conductor. The first, second, and thirdconduits may be electrically isolated from the first, second, and thirdconductors. Each conductor-in-conduit heater in a 3-phase Y electricalconfiguration may be dimensioned to generate approximately 650 watts permeter of conductor to approximately 1650 watts per meter of conductor.

[1050] Heat may be generated by the conductor-in-conduit heater withinan open wellbore. Generated heat may radiatively heat a portion of arelatively permeable formation adjacent to the conductor-in-conduitheater. To a lesser extent, gas conduction adjacent to theconductor-in-conduit heater heats the portion of the formation. Using anopen wellbore completion may reduce casing and packing costs associatedwith filling the opening with a material to provide conductive heattransfer between the insulated conductor and the formation. In addition,heat transfer by radiation may be more efficient than heat transfer byconduction in a formation, so the heaters may be operated at lowertemperatures using radiative heat transfer. Operating at a lowertemperature may extend the life of the heat source and/or reduce thecost of material needed to form the heat source.

[1051] The conductor-in-conduit heater may be installed in opening 514.In an embodiment, the conductor-in-conduit heater may be installed intoa well by sections. For example, a first section of theconductor-in-conduit heater may be suspended in a wellbore by a rig. Thesection may be about 12 m in length. A second section (e.g., ofsubstantially similar length) may be coupled to the first section in thewell. The second section may be coupled by welding the second section tothe first section and/or with threads disposed on the first and secondsection. An orbital welder disposed at the wellhead may weld the secondsection to the first section. The first section may be lowered into thewellbore by the rig. This process may be repeated with subsequentsections coupled to previous sections until a heater of desired lengthis placed in the wellbore. In some embodiments, three sections may bewelded together prior to being placed in the wellbore. The welds may beformed and tested before the rig is used to attach the three sections toa string already placed in the ground. The three sections may be liftedby a crane to the rig. Having three sections already welded together mayreduce installation time of the heat source.

[1052] Assembling a heat source at a location proximate a formation(e.g., at the site of a formation) may be more economical than shippinga pre-formed heat source and/or conduits to the hydrocarbon formation.For example, assembling the heat source at the site of the formation mayreduce costs for transporting assembled heat sources over longdistances. In addition, heat sources may be more easily assembled invarying lengths and/or of varying materials to meet specific formationrequirements at the formation site. For example, a portion of a heatsource that is to be heated may be made of a material (e.g., 304stainless steel or other high temperature alloy) while a portion of theheat source in the overburden may be made of carbon steel. Forming theheat source at the site may allow the heat source to be specificallymade for an opening in the formation so that the portion of the heatsource in the overburden is carbon steel and not a more expensive, heatresistant alloy. Heat source lengths may vary due to varying formationlayer depths and formation properties. For example, a formation may havea varying thickness and/or may be located underneath rolling terrain,uneven surfaces, and/or an overburden with a varying thickness. Heatsources of varying length and of varying materials may be assembled onsite in lengths determined by the depth of each opening in theformation.

[1053]FIG. 86 depicts an embodiment for assembling aconductor-in-conduit heat source and installing the heat source in aformation. The conductor-in-conduit heat source may be assembled inassembly facility 8650. In some embodiments, the heat source isassembled from conduits shipped to the formation site. In otherembodiments, heat sources may be made from plate stock that is formedinto conduits at the assembly facility. An advantage of forming aconduit at the assembly facility may be that a surface of plate stockmay be treated with a desired coating (e.g., a coating that allows theemissivity to approach one) or cladding (e.g., copper cladding) beforeforming the conduit so that the treated surface is an inside surface ofthe conduit. In some embodiments, portions of heat sources may be formedfrom plate stock at the assembly facility, while other portions of theheat source may be formed from conduits shipped to the formation site.

[1054] Individual conductor-in-conduit heat source 8652 may includeconductor 580 and conduit 582 as shown in FIG. 87. In an embodiment,conductor 580 and conduit 582 heat sources may be made of a number ofjoined together sections. In an embodiment, each section is a standard40 ft (12.2 m) section of pipe. Other section lengths may also be formedand/or utilized. In addition, sections of conductor 580 and/or conduit582 may be treated in assembly facility 8650 before, during, or afterassembly. The sections may be treated, for example, to increase anemissivity of the sections by roughening and/or oxidation of thesections.

[1055] Each conductor-in-conduit heat source 8652 may be assembled in anassembly facility. Components of conductor-in-conduit heat source 8652may be placed on or within individual conductor-in-conduit heat source8652 in the assembly facility. Components may include, but are notlimited to, one or more centralizers, low resistance sections, slidingconnectors, insulation layers, and coatings, claddings, or couplingmaterials.

[1056] As shown in FIG. 86, each individual conductor-in-conduit heatsource 8652 may be coupled to at least one individualconductor-in-conduit heat source 8652 at coupling station 8656 to formconductor-in-conduit heat source of desired length 8654. The desiredlength may be, for example, a length of a conductor-in-conduit heatsource specified for a selected opening in a formation. In certainembodiments, coupling individual conductor-in-conduit heat source 8652to at least one additional individual conductor-in-conduit heat source8652 includes welding the individual conductor-in-conduit heat source toat least one additional individual conductor-in-conduit heat source. Inone embodiment, welding each individual conductor-in-conduit heat source8652 to an additional individual conductor-in-conduit heat source isaccomplished by forge welding two adjacent sections together.

[1057] In some embodiments, sections of welded togetherconductor-in-conduit heat source of desired length 8654 are placed on abench, holding tray or in an opening in the ground until the entirelength of the heat source is completed. Weld integrity may be tested aseach weld is formed. For example, weld integrity may be tested by anon-destructive testing method such as x-ray testing, acoustic testing,and/or electromagnetic testing. After an entire length ofconductor-in-conduit heat source of desired length 8654 is completed,the conductor-in-conduit heat source of desired length may be coiledonto spool 8660 in a direction of arrow 8662. Coilingconductor-in-conduit heat source of desired length 8654 may make theheat source easier to transport to an opening in a formation. Forexample, conductor-in-conduit heat source of desired length 8654 may bemore easily transported by truck or train to an opening in theformation.

[1058] In some embodiments, a set length of welded togetherconductor-in-conduit may be coiled onto spool 8660 while other sectionsare being formed at coupling station 8656. In some embodiments, theassembly facility may be a mobile facility (e.g., placed on one or moretrain cars or semi-trailers) that can be moved to an opening in aformation. After forming a welded together length ofconductor-in-conduit with components (e.g., centralizers, coatings,claddings, sliding connectors), the conductor-in-conduit length may belowered into the opening in the formation.

[1059] In certain embodiments, conductor-in-conduit heat source ofdesired length 8654 may be tested at testing station 8658 before coilingthe heat source. Testing station 8658 may be used to test a completedconductor-in-conduit heat source of desired length 8654 or sections ofthe conductor-in-conduit heat source of desired length. Testing station8658 may be used to test selected properties of conductor-in-conduitheat source of desired length 8654. For example, testing station 8658may be used to test properties such as, but not limited to, electricalconductivity, weld integrity, thermal conductivity, emissivity, andmechanical strength. In one embodiment, testing station 8658 is used totest weld integrity with an Electro-Magnetic Acoustic Transmission(EMAT) weld inspection technique.

[1060] Conductor-in-conduit heat source of desired length 8654 may becoiled onto spool 8660 for transporting from assembly facility 8650 toan opening in a formation and installation into the opening. In anembodiment, assembly facility 8650 is located at a site of theformation. For example, assembly facility 8650 may be part of a surfacefacility used to treat fluids from the formation or located a proximateto the formation (e.g., less than about 10 km from the formation or, insome embodiments, less than about 20 km or less than about 30 km). Othertypes of heat sources (e.g., insulated conductor heat sources, naturaldistributed combustor heat sources, etc.) may also be assembled inassembly facility 8650. These other heat sources may also be spooledonto spool 8660, transported to an opening in a formation, and installedinto the opening as is described for conductor-in-conduit heat source ofdesired length 8654.

[1061] Transportation of conductor-in-conduit heat source of desiredlength 8654 to an opening in a formation is represented by arrow 8664 inFIG. 86. Transporting conductor-in-conduit heat source of desired length8654 may include transporting the heat source on a bed, trailer, a cartof a truck or train, or a coiled tubing unit. In some embodiments, morethan one heat source may be placed on the bed. Each heat source may beinstalled in a separate opening in the formation. In one embodiment, atrain system (e.g., rail system) may be set up to transport heat sourcesfrom assembly facility 8650 to each of the openings in the formation. Insome instances, a lift and move track system may be used in which traintracks are lifted and moved to another location after use in onelocation.

[1062] After spool 8660 with conductor-in-conduit heat source of desiredlength 8654 has been transported to opening 514, the heat source may beuncoiled and installed into the opening in a direction of arrow 8666.Conductor-in-conduit heat source of desired length 8654 may be uncoiledfrom spool 8660 while the spool remains on the bed of a truck or train.In some embodiments, more than one conductor-in-conduit heat source ofdesired length 8654 may be installed at one time. In one embodiment,more than one heat source may be installed into one opening 514. Spool8660 may be re-used for additional heat sources after installation ofconductor-in-conduit heat source of desired length 8654. In someembodiments, spool 8660 may be used to removed conductor-in-conduit heatsource of desired length 8654 from the opening. Conductor-in-conduitheat source of desired length 8654 may be re-coiled onto spool 8660 asthe heat source is removed from opening 514. Subsequently,conductor-in-conduit heat source of desired length 8654 may bere-installed from spool 8660 into opening 514 or transported to analternate opening in the formation and installed the alternate opening.

[1063] In certain embodiments, conductor-in-conduit heat source ofdesired length 8654, or any heat source (e.g., an insulated conductorheat source), may be installed such that the heat source is removablefrom opening 514. The heat source may be removable so that the heatsource can be repaired or replaced if the heat source fails or breaks.In other instances, the heat source may be removed from the opening andtransported and reused in another opening in the formation (or in adifferent formation) at a later time. Being able to remove, replace,and/or reuse a heat source may be economically favorable for reducingequipment and/or operating costs. In addition, being able to remove andreplace an ineffective heater may eliminate the need to form wellboresin close proximity to existing wellbores that have failed heaters in aheated or heating formation.

[1064] In some embodiments, a conduit of a desired length may be placedinto opening 514 before a conductor of the desired length. The conductorand the conduit of the desired length may be assembled in assemblyfacility 8650. The conduit of the desired length may be installed intoopening 514. After installation of the conduit of the desired length,the conductor of the desired length may be installed into opening 514.In an embodiment, the conduit and the conductor of the desired lengthare coiled onto a spool in assembly facility 8650 and uncoiled from thespool for installation into opening 514. Components (e.g., centralizers581, sliding connectors 583, etc.) may be placed on the conductor orconduit as the conductor is installed into the conduit and opening 514.

[1065] In certain embodiments, centralizer 581 may include at least twoportions coupled together to form the centralizer (e.g., “clam shell”centralizers). In one embodiment, the portions are placed on a conductorand coupled together as the conductor is installed into a conduit oropening. The portions may be coupled with fastening devices such as, butnot limited to, clamps, bolts, screws, snap-locks, and/or adhesive. Theportions may be shaped such that a first portion fits into a secondportion. For example, an end of the first portion may have a slightlysmaller width than an end of the second portion so that the ends overlapwhen the two portions are coupled.

[1066] In some embodiments, low resistance section 584 is coupled toconductor-in-conduit heat source of desired length 8654 in assemblyfacility 8650. In other embodiments, low resistance section 584 iscoupled to conductor-in-conduit heat source of desired length 8654 afterthe heat source is installed into opening 514. Low resistance section584 of a desired length may be assembled in assembly facility 8650. Anassembled low resistance conductor may be coiled onto a spool. Theassembled low resistance conductor may be uncoiled from the spool andcoupled to conductor-in-conduit heat source of desired length 8654 afterthe heat source is installed in opening 514. In another embodiment, lowresistance section 584 is assembled as the low resistance conductor iscoupled to conductor-in-conduit heat source of desired length 8654 andinstalled into opening 514. Conductor-in-conduit heat source of desiredlength 8654 may be coupled to a support after installation so that lowresistance section 584 is coupled to the installed heat source.

[1067] Assembling a desired length of a low resistance conductor mayinclude coupling individual low resistance conductors together. Theindividual low resistance conductors may be plate stock conductorsobtained from a manufacturer. The individual low resistance conductorsmay be coupled to an electrically conductive material to lower theelectrical resistance of the low resistance conductor. The electricallyconductive material may be coupled to the individual low resistanceconductor before assembly of the desired length of low resistanceconductor. In one embodiment, the individual low resistance conductorsmay have threaded ends that are coupled together. In another embodiment,the individual low resistance conductors may have ends that are weldedtogether. Ends of the individual low resistance conductors may be shapedsuch that an end of a first individual low resistance conductor fitsinto an end of a second individual low resistance conductor. Forexample, an end of a first individual low resistance conductor may be afemale-shaped end while an end of a second individual low resistanceconductor is a male-shaped end.

[1068] In another embodiment, a conductor-in-conduit heat source of adesired length may be assembled at a wellbore (or opening) in aformation and installed into the wellbore as the conductor-in-conduitheat source is assembled. Individual conductors may be coupled to form afirst section of a conductor of desired length. Similarly, conduits maybe coupled to form a first section of a conduit of desired length. Thefirst formed sections of the conductor and the conduit may be installedinto the wellbore. The first formed sections of the conductor and theconduit may be electrically coupled at a first end that is installedinto the wellbore. The first sections of the conductor and conduit may,in some embodiments, be coupled substantially simultaneously. Additionalsections of the conductor and/or conduit may be formed during or afterinstallation of the first formed sections. The additional sections ofthe conductor and/or conduit may be coupled to the first formed sectionsof the conductor and/or conduit and installed into the wellbore.Centralizers and/or other components may be coupled to sections of theconductor and/or conduit and installed with the conductor and theconduit into the wellbore.

[1069] A method for coupling conductors or conduits may include a forgewelding method (e.g., shielded active gas (SAG) welding). In anembodiment, forge welding includes arranging ends of the conductorsand/or conduits that are to be interconnected at a selected distance.Seals may be formed against walls of the conduit and/or conductor todefine a chamber. A flushing, reducing fluid may be introduced into thechamber. Each end within the chamber may be heated and moved towardsanother end until the heated ends contact each other. Contacting theheated ends may form a forge weld between the heated ends. The flushing,reducing fluid mixture may include less than 25% by volume of a reducingagent and more than 75% by volume of a substantially inert gas. Theflushing, reducing fluid may inhibit oxidation reactions that canadversely affect weld integrity.

[1070] A flushing fluid mixture with less than 25% by volume of areducing fluid (e.g., hydrogen and/or carbon monoxide) and more than 75%by volume of a substantially inert gas (e.g., nitrogen, argon, and/orcarbon dioxide) may be non-explosive when the flushing fluid mixturecomes into contact with air at elevated temperatures needed to form theforge weld. In some embodiments, the reducing agent may be or includeborax powder and/or beryllium or alkaline hydrites. The flushing fluidmixture may contain a sufficient amount of a reducing gas to flush offoxidized skin from the hot ends that are to be interconnected. In someembodiments, the non-explosive flushing fluid mixture includes between2% by volume and 10% by volume of the reducing fluid and between 90% byvolume and 98% by volume of the substantially inert gas. In certainembodiments, the mixture includes about 5% by volume of the reducingfluid and about 95% by volume of the substantially inert gas. In oneembodiment, a non-explosive flushing fluid mixture includes about 95% byvolume of nitrogen and about 5% by volume of hydrogen. The non-explosiveflushing fluid mixture may also include less than 100 ppm H₂O and/or O₂or, in some cases, less than 15 ppm H₂O and/or O₂.

[1071] A substantially inert gas used during a forge welding procedureis a gas that does not significantly react with the metals to be forgedwelded at the pressures and temperatures used during forge welding.Substantially inert gas may be, but is not limited to, noble gases(e.g., helium and argon), nitrogen or combinations thereof.

[1072] A non-explosive flushing fluid mixture may be formed in-situwithin the chamber. A coating on the conduits and/or conductors may bepresent and/or a solid may be placed in the chamber. When the conduitsand/or conductors are heated, the coating and/or solid may be react orphysically transform to the flushing fluid mixture.

[1073] In an embodiment, ends of conductors or conduits are heated bymeans of high frequency electrical heating. The ends may be maintainedat a predetermined spacing of between 1 mm and 4 mm from each other by agripping assembly while being heated. Electrical contacts may be pressedat circumferentially spaced intervals against the wall of each conduitand/or conductor adjacent to the end such that the electrical contactstransmit a high frequency electrical current in a substantiallycircumferential direction in the segment between the electricalcontacts.

[1074] To equalize the level of heating in a circumferential direction,each end may be heated by at least two pairs of electrodes. Theelectrodes of each pair may be pressed at substantially diametricallyopposite positions against walls of the conduits and/or conductors. Thedifferent pairs of electrodes at each end may be activated in analternating manner.

[1075] In one embodiment, two pairs of diametrically opposite electrodesare pressed at angular intervals of substantially 90° against walls ofthe conductors and conduits In another embodiment, three pairs ofdiametrically opposite electrodes are pressed at angular intervals ofsubstantially 60° against the walls of the conductors and conduits. Inother embodiments, four, five, six or more pairs of diametricallyopposite electrodes may be used and activated in an alternating mannerto equalize the level of heating of the ends in the circumferentialdirection.

[1076] The use of two or more pairs of electrodes may reduce unequalheating of the pipe ends because of over heating of the walls in thedirect vicinity of the electrode. In addition, using two or more pairsof electrodes may reduce heating of the pipe wall halfway between theelectrodes.

[1077] In another embodiment, the ends may be heated by a directresistance heating method. The direct resistance heating method mayinclude transmitting a large current in an axial direction across theconduits and/or conductors while the conduits and/or conductors arepressed together. In another embodiment, the ends may be heated byinduction heating. Induction heating may include using external and/orinternal heating coils to create an electromagnetic field that induceselectrical currents in the conduits and/or conductors. The electricalcurrents may resistively heat the conduits.

[1078] The heating assembly may be used to give the forge welded ends apost weld heat treatment. The post weld heat treatment may includeproviding at least some heating to the ends such that the ends arecooled down at a predetermined temperature decrease rate (i.e., cooldown rate). In some embodiments, the assembly may be equipped with waterand/or forced air injectors to increase and/or control the cool downrate of the forge welded ends.

[1079] In certain embodiments, the quality of the forge weld formedbetween the interconnected conduits and/or conductors is inspected bymeans of an Electro-Magnetic Acoustic Transmission weld inspectiontechnique (EMAT). EMAT may include placing at least one electromagneticcoil adjacent to both sides of the forge welded joint. The coil may beheld at a predetermined distance from the conduits and/or conductorsduring the inspection process. The absence of physical contact betweenthe wall of the hot conduits and/or conductors and the coils of the EMATinspection tool may enable weld inspection immediately after the forgeweld joint has been made.

[1080]FIG. 88 shows an end of tubular 9150 around which two pairs ofdiametrically opposite electrodes 9152, 9153 and 9154, 9155 arearranged. Tubular 9150 may be a conduit or conductor. Tubular 9150 maybe made of electrically conductive material (e.g., stainless steel). Thefirst pair of electrodes 9152, 9153 may be pressed against the outersurface of tubular 9150 and transmit high frequency current 9156 throughthe wall of the tubular as illustrated by arrows 9157. An assembly offerrite bars 9158 may serve to enhance the current density in theimmediate vicinity of the ends of the tubular 9150 and of the adjacenttubular to which tubular 9150 is to be welded.

[1081]FIG. 89 depicts an embodiment with ends 9162, 9162A of twoadjacent tubulars 9150 and 9150A. Tubulars 9150 and 9150A may be heatedby two sets of diametrically opposite electrodes 9152, 9153, 9154, 9155and 9152A, 9153A, 9154A and 9155A, respectively.

[1082] Tubular ends 9162 and 9162A may be located at a few millimetersdistant from each other during a heating phase. The larger spacing ofcurrent density arrows 9157 midway between electrodes 9152, 9153illustrates that the current density midway between these electrodes maybe lower than the current density adjacent to each of the electrodes.The lower current density midway between the electrodes may create avariation in the heating rate of the tubular ends 9162 and 9162A. Toreduce a possible irregular heating rate, electrodes 9152, 9153 and9152A, 9153A may be regularly lifted from the outer surface of tubulars9150, 9150A while the other electrodes 9154, 9154A and 9155, 9155A arepressed against the outer surface of the tubulars 9150, 9150A andactivated to transmit a high frequency current through the ends of thetubulars. By sequentially activating the two sets of diametricallyopposite electrodes at each tubular end, irregular heating of thetubular ends may be inhibited (i.e., heating of the tubular ends may bemore uniform).

[1083] All electrodes 9152-9155 and 9152A-9155A shown in FIG. 89 may bepressed simultaneously against tubular ends 9150 and 9150A ifalternating current supplied to the electrodes is controlled such thatduring a first part of a current cycle the diametrically oppositeelectrode pairs 9152A, 9153A and 9154, 9155 transmit a positiveelectrical current as indicated by the “+” sign in FIG. 89, whereaselectrodes 9152, 9153, and 9154A, 9155A transmit a negative electricalcurrent as indicated by the “−” sign. During a second part of thealternating current cycle, electrodes 9152A, 9153A, and 9154, 9155transmit a negative electrical current, whereas electrodes 9152, 9153,and 9154A, 9155A transmit a positive current into tubulars 9150 and9150A. Controlling the alternating current in this manner may heattubular ends 9162 and 9162A in a substantially uniform manner.

[1084] The temperature of heated tubular ends 9162, 9162A may bemonitored by an infrared temperature sensor. When the monitoredtemperature has reached a temperature sufficient to make a forge weld,tubular ends 9162, 9162A may be pressed onto each other such that aforge weld is made. Tubular ends 9162, 9162A may be profiled and have asmaller wall thickness than other parts of tubulars 9150, 9150A tocompensate for the deformation of the tubular ends when the ends areabutted. Profiling the tubular ends may allow tubulars 9150, 9150A tohave a substantially uniform wall thickness at forge welded ends.

[1085] During the heating phase and while the ends of tubulars 9150,9150A are moved towards each other, the tubular ends may be encased,both internally and externally, in a chamber 9168. Chamber 9168 may befilled with a non-explosive flushing fluid mixture.

[1086] The non-explosive flushing fluid mixture may include more than75% by volume of nitrogen and less than 25% by volume of hydrogen. Inone embodiment, the non-explosive flushing fluid mixture forinterconnecting steel tubulars 9150, 9150A includes about 5% by volumeof hydrogen and about 95% by volume of nitrogen. The flushing fluidpressure in a part of chamber 9168 outside the tubulars 9150 and 9150Amay be higher than the flushing fluid pressure in a part of the chamber9168 within the interior of the tubulars such that throughout theheating process the flushing fluid flows along the ends of the tubularsas illustrated by arrows 9169 until the ends of the tubulars are forgedtogether. In some embodiments, flushing fluid may flow through thechamber.

[1087] Hydrogen in the flushing fluid may react with oxidized metal onthe ends 9162, 9162A of the tubulars 9150, 9150A so that formation of anoxidized skin is inhibited. Inhibition of an oxidized skin may allowformation of a forge weld with minimal amounts of corroded metalinclusions.

[1088] Laboratory experiments reveal that a good metallurgical bondbetween stainless steel tubulars may be obtained by forge welding with aflushing fluid containing about 5% by volume of hydrogen and about 95%by volume of nitrogen. Experiments also show that such a flushing fluidmixture may be non-explosive during and after forge welding. Two forgewelded stainless steel tubulars failed during at a location away fromthe forge weld when the tubulars were subjected to testing.

[1089] In an embodiment, the tubular ends are clamped throughout theforge welding process to a gripping assembly. Clamping the tubular endsmay maintain the tubular ends at a predetermined spacing of between 1 mmand 4 mm from each other during the heating phase. The gripping assemblymay include a mechanical stop that interrupts axial movement of theheated tubular ends during the forge welding process after the heatedtubular ends have moved a predetermined distance towards each other. Theheated tubular ends may be pressed into each other such that a highquality forge weld is created without significant deformation of theheated ends.

[1090] In certain embodiments, electrodes 9152-9155 and 9152A-9155A mayalso be activated to give the forged tubular ends a post weld heattreatment. Electrical power 9156 supplied to the electrodes during thepost weld heat treatment may be lower than during the heat up phasebefore the forge welding operation. Electrical power 9156 suppliedduring the post weld heat treatment may be controlled in conjunctionwith temperature measured by an infrared temperature sensor(s) such thatthe temperature of the forge welded tubular ends is decreased inaccordance with a predetermined temperature decrease or cooling cycle.

[1091] The quality of the forge weld may be inspected by a hybridelectromagnetic acoustic transmission technique which is known as EMAT.EMAT is described in U.S. Pat. Nos. 5,652,389 to Schaps et al.,5,760,307 to Latimer et al., 5,777,229 to Geier et al., and 6,155,117 toStevens et al., each of which is incorporated by reference as if fullyset forth herein. The EMAT technique makes use of an induction coilplaced at one side of the welded joint. The induction coil may inducemagnetic fields that generate electromagnetic forces in the surface ofthe welded joint. These forces may produce a mechanical disturbance bycoupling to the atomic lattice through a scattering process. Inelectromagnetic acoustic generation, the conversion may take placewithin a skin depth of material (i.e., the metal surface acts as atransducer). The reception may take place in a reciprocal way in areceiving coil. When the elastic wave strikes the surface of theconductor in the presence of a magnetic field, induced currents may begenerated in the receiving coil, similar to the operation of an electricgenerator. An advantage of the EMAT weld inspection technology is thatthe inductive transmission and receiving coils do not have to contactthe welded tubular. Thus, the inspection may be done soon after theforge weld is made (e.g., when the forge welded tubulars are still toohot to allow physical contact with an inspection probe).

[1092] Using the SAG method to weld tubular ends of heat sources mayinhibit changes in the metallurgy of the tubular materials. For example,the elemental composition of the weld joint may be substantially similarto the elemental composition of the tubulars. Inhibiting changes inmetallurgy may reduce the need for heat-treatment of the tubulars beforeuse of the tubulars. The SAG method also appears not to change the grainstructure of the near-weld section of the tubulars. Maintaining thegrain structure of the tubulars may inhibit corrosion and/or creep inthe tubulars during use.

[1093]FIG. 90 illustrates an end view of an embodiment of aconductor-in-conduit heat source heated by diametrically oppositeelectrodes. Conductor 580 may be placed within conduit 582. Conductor580 may be heated by two sets of diametrically opposite electrodes 9152,9153, 9154, 9155. Conduit 582 may be heated by two sets of diametricallyopposite electrodes 9172, 9173, 9174, 9175. Conductor 580 and conduits582 may be heated and forge welded together as described in theembodiments of FIGS. 88-89. In some embodiments, two ends of conductors580 are forged welded together and then two ends of conduits 582 areforged together in a second procedure.

[1094]FIG. 91 illustrates a cross-sectional representation of anembodiment of two sections of a conductor-In-conduit heat source beforebeing forge welded. During heating of conductors 580, 580A and conduits582, 582A and while the ends of the conductors and the conduits aremoved towards each other, ends of the conductors and conduits may beencased in a chamber 9176. Chamber 9176 may be filled with thenon-explosive flushing fluid mixture. Plugs 9178, 9178A may be placed inthe annular space between conductors 580, 580A and conduits 582, 582A.In an embodiment, the plugs may be inflated to seal the annular space.Plugs 9178, 9178A may inhibit the flow of the flushing fluid mixturethrough the annular space between conductors 580, 580A and conduits 582,582A. The flushing fluid pressure in a part of chamber 9176 outside theconduits 582, 582A may be higher than the flushing fluid pressure insidethe conduits and outside conductors 580, 580A. Similarly, the flushingfluid pressure outside conductors 580, 580A may be higher than theflushing fluid pressure inside the conductors. Due to the pressuredifferentials throughout the heating process, the flushing fluid tendsto flow along the ends of the tubulars as illustrated by arrows 9179until the ends of the conductors and conduits are forged together.

[1095]FIG. 92 depicts an embodiment of three horizontal heat sourcesplaced in a formation. Wellbore 9632 may be formed through overburden540 and into hydrocarbon layer 516. Wellbore 9632 may be formed by anystandard drilling method. In certain embodiments, wellbore 9632 isformed substantially horizontally in hydrocarbon layer 516. In someembodiments, wellbore 9632 may be formed at other angles withinhydrocarbon layer 516.

[1096] One or more conduits 9634 may be placed within wellbore 9632. Aportion of wellbore 9632 and/or second wellbores may include casings.Conduit 9634 may have a smaller diameter than wellbore 9632. In anembodiment, wellbore 9632 has a diameter of about 30.5 cm and conduit9634 has a diameter of about 14 cm. In an embodiment, an inside diameterof a casing in conduit 9634 may be about 12 cm. Conduits 9634 may haveextended sections 9635 that extend beyond the end of wellbore 9632 inhydrocarbon layer 516. Extended sections 9635 may be formed inhydrocarbon layer 516 by drilling or other wellbore forming methods. Inan embodiment, extended sections 9635 extend substantially horizontallyinto hydrocarbon layer 516. In certain embodiments, extended sections9635 may somewhat diverge as represented in FIG. 92.

[1097] Perforated casings 9636 may be placed in extended sections 9635of conduits 9634. Perforated casings 9636 may provide support for theextended sections so that collapse of wellbores is inhibited duringheating of the formation. Perforated casings 9636 may be steel (e.g.,carbon steel or stainless steel). Perforated casings 9636 may beperforated liners that expand within the wellbores (expandabletubulars). Expandable tubulars are described in U.S. Pat. Nos. 5,366,012to Lohbeck, and 6,354,373 to Vercaemer et al., each of which isincorporated by reference as if fully set forth herein. In anembodiment, perforated casings 9636 are formed by inserting a perforatedcasing into each of extended sections 9635 and expanding the perforatedcasing within each extended section. The perforated casing may beexpanded by pulling an expander tool shaped to push the perforatedcasing towards the wall of the wellbore (e.g., a pig) along the lengthof each extended section 9635. The expander tool may push eachperforated casing beyond the yield point of the perforated casing.

[1098] After installation of perforated casings 9636, heat sources 9638may be installed into extended sections 9635. Heat sources 9638 may beused to provide heat to hydrocarbon layer 516 along the length ofextended sections 9635. Heat sources 9638 may include heat sources suchas conductor-in-conduit heaters, insulated conductor heaters, etc. Insome embodiments, heat sources 9638 have a diameter of about 7.3 cm.Perforated casings 9636 may allow for production of formation fluid fromthe heat source wellbores. Installation of heat sources 9638 inperforated casings 9636 may also allow the heat sources to be removed ata later time. Heat sources 9638 may, for example, be removed for repair,replacement, and/or used in another portion of a formation.

[1099] In an embodiment, an elongated member may be disposed within anopening (e.g., an open wellbore) in a relatively permeable formation.The opening may be an uncased opening in the relatively permeableformation. The elongated member may be a length (e.g., a strip) of metalor any other elongated piece of metal (e.g., a rod). The elongatedmember may include stainless steel. The elongated member may be made ofa material able to withstand corrosion at high temperatures within theopening.

[1100] An elongated member may be a bare metal heater. “Bare metal”refers to a metal that does not include a layer of electricalinsulation, such as mineral insulation, that is designed to provideelectrical insulation for the metal throughout an operating temperaturerange of the elongated member. Bare metal may encompass a metal thatincludes a corrosion inhibiter such as a naturally occurring oxidationlayer, an applied oxidation layer, and/or a film. Bare metal includesmetal with polymeric or other types of electrical insulation that cannotretain electrical insulating properties at typical operating temperatureof the elongated member. Such material may be placed on the metal andmay be thermally degraded during use of the heater.

[1101] An elongated member may have a length of about 650 m. Longerlengths may be achieved using sections of high strength alloys, but suchelongated members may be expensive. In some embodiments, an elongatedmember may be supported by a plate in a wellhead. The elongated membermay include sections of different conductive materials that are weldedtogether end-to-end. A large amount of electrically conductive weldmaterial may be used to couple the separate sections together toincrease strength of the resulting member and to provide a path forelectricity to flow that will not result in arcing and/or corrosion atthe welded connections. In some embodiments, different sections may beforge welded together. The different conductive materials may includealloys with a high creep resistance. The sections of differentconductive materials may have varying diameters to ensure uniformheating along the elongated member. A first metal that has a highercreep resistance than a second metal typically has a higher resistivitythan the second metal. The difference in resistivities may allow asection of larger cross-sectional area, more creep resistant first metalto dissipate the same amount of heat as a section of smallercross-sectional area second metal. The cross-sectional areas of the twodifferent metals may be tailored to result in substantially the sameamount of heat dissipation in two welded together sections of themetals. The conductive materials may include, but are not limited to,617 Inconel, HR-120, 316 stainless steel, and 304 stainless steel. Forexample, an elongated member may have a 60 meter section of 617 Inconel,60 meter section of HR-120, and 150 meter section of 304 stainlesssteel. In addition, the elongated member may have a low resistancesection that may run from the wellhead through the overburden. This lowresistance section may decrease the heating within the formation fromthe wellhead through the overburden. The low resistance section may bethe result of, for example, choosing a electrically conductive materialand/or increasing the cross-sectional area available for electricalconduction.

[1102] In a heat source embodiment, a support member may extend throughthe overburden, and the bare metal elongated member or members may becoupled to the support member. A plate, a centralizer, or other type ofsupport member may be located near an interface between the overburdenand the hydrocarbon layer. A low resistivity cable, such as a strandedcopper cable, may extend along the support member and may be coupled tothe elongated member or members. The low resistivity cable may becoupled to a power source that supplies electricity to the elongatedmember or members.

[1103]FIG. 93 illustrates an embodiment of a plurality of elongatedmembers that may heat a relatively permeable formation. Two or more(e.g., four) elongated members 600 may be supported by support member604. Elongated members 600 may be coupled to support member 604 usinginsulated centralizers 602. Support member 604 may be a tube or conduit.Support member 604 may also be a perforated tube. Support member 604 mayprovide a flow of an oxidizing fluid into opening 514. Support member604 may have a diameter between about 1.2 cm to about 4 cm and, in someembodiments, about 2.5 cm. Support member 604, elongated members 600,and insulated centralizers 602 may be disposed in opening 514 inhydrocarbon layer 516. Insulated centralizers 602 may maintain alocation of elongated members 600 on support member 604 such thatlateral movement of elongated members 600 is inhibited at temperatureshigh enough to deform support member 604 or elongated members 600.Elongated members 600, in some embodiments, may be metal strips of about2.5 cm wide and about 0.3 cm thick stainless steel. Elongated members600, however, may also include a pipe or a rod formed of a conductivematerial. Electrical current may be applied to elongated members 600such that elongated members 600 may generate heat due to electricalresistance.

[1104] Elongated members 600 may generate heat of approximately 650watts per meter of elongated members 600 to approximately 1650 watts permeter of elongated members 600. Elongated members 600 may be attemperatures of approximately 480° C. to approximately 815° C.Substantially uniform heating of a relatively permeable formation may beprovided along a length of elongated members 600 or greater than about305 m or, maybe even greater than about 610 m.

[1105] Elongated members 600 may be electrically coupled in series.Electrical current may be supplied to elongated members 600 usinglead-in conductor 572. Lead-in conductor 572 may be coupled to wellhead690. Electrical current may be returned to wellhead 690 using lead-outconductor 606 coupled to elongated members 600. Lead-in conductor 572and lead-out conductor 606 may be coupled to wellhead 690 at surface 550through a sealing flange located between wellhead 690 and overburden540. The sealing flange may inhibit fluid from escaping from opening 514to the surface 550 and/or atmosphere. Lead-in conductor 572 and lead-outconductor 606 may be coupled to elongated members using a cold pintransition conductor. The cold pin transition conductor may include aninsulated conductor of low resistance. Little or no heat may begenerated in the cold pin transition conductor. The cold pin transitionconductor may be coupled to lead-in conductor 572, lead-out conductor606, and/or elongated members 600 by splices, mechanical connectionsand/or welds. The cold pin transition conductor may provide atemperature transition between lead-in conductor 572, lead-out conductor606, and/or elongated members 600. Lead-in conductor 572 and lead-outconductor 606 may be made of low resistance conductors so thatsubstantially no heat is generated from electrical current passingthrough lead-in conductor 572 and lead-out conductor 606.

[1106] Weld beads may be placed beneath the centralizers 602 on supportmember 604 to fix the position of the centralizers. Weld beads may beplaced on elongated members 600 above the uppermost centralizer to fixthe position of the elongated members relative to the support member(other types of connecting mechanisms may also be used). When heated,the elongated member may thermally expand downwards. The elongatedmember may be formed of different metals at different locations along alength of the elongated member to allow relatively long lengths to beformed. For example, a “U” shaped elongated member may include a firstlength formed of 310 stainless steel, a second length formed of 304stainless steel welded to the first length, and a third length formed of310 stainless steel welded to the second length. 310 stainless steel ismore resistive than 304 stainless steel and may dissipate approximately25% more energy per unit length than 304 stainless steel of the samedimensions. 310 stainless steel may be more creep resistant than 304stainless steel. The first length and the third length may be formedwith cross-sectional areas that allow the first length and third lengthsto dissipate as much heat as a smaller cross-sectional area of 304stainless steel. The first and third lengths may be positioned close towellhead 690. The use of different types of metal may allow theformation of long elongated members. The different metals may be, butare not limited to, 617 Inconel, HR120, 316 stainless steel, 310stainless steel, and 304 stainless steel.

[1107] Packing material 542 may be placed between overburden casing 541and opening 514. Packing material 542 may inhibit fluid flowing fromopening 514 to surface 550 and to inhibit corresponding heat lossestowards the surface. In some embodiments, overburden casing 541 may beplaced in cement 544 in overburden 540. In other embodiments, overburdencasing may not be cemented to the formation. Surface conductor 545 maybe disposed in cement 544. Support member 604 may be coupled to wellhead690 at surface 550. Centralizer 581 may maintain a location of supportmember 604 within overburden casing 541. Electrical current may besupplied to elongated members 600 to generate heat. Heat generated fromelongated members 600 may radiate within opening 514 to heat at least aportion of hydrocarbon layer 516.

[1108] The oxidizing fluid may be provided along a length of theelongated members 600 from oxidizing fluid source 508. The oxidizingfluid may inhibit carbon deposition on or proximate the elongatedmembers. For example, the oxidizing fluid may react with hydrocarbons toform carbon dioxide. The carbon dioxide may be removed from the opening.Openings 605 in support member 604 may provide a flow of the oxidizingfluid along the length of elongated members 600. Openings 605 may becritical flow orifices. In some embodiments, a conduit may be disposedproximate elongated members 600 to control the pressure in the formationand/or to introduce an oxidizing fluid into opening 514. Without a flowof oxidizing fluid, carbon deposition may occur on or proximateelongated members 600 or on insulated centralizers 602. Carbondeposition may cause shorting between elongated members 600 andinsulated centralizers 602 or hot spots along elongated members 600. Theoxidizing fluid may be used to react with the carbon in the formation.The heat generated by reaction with the carbon may complement orsupplement electrically generated heat.

[1109] In a heat source embodiment, a bare metal elongated member may beformed in a “U” shape (or hairpin) and the member may be suspended froma wellhead or from a positioner placed at or near an interface betweenthe overburden and the formation to be heated. In certain embodiments,the bare metal heaters are formed of rod stock. Cylindrical, highalumina ceramic electrical insulators may be placed over legs of theelongated members. Tack welds along lengths of the legs may fix theposition of the insulators. The insulators may inhibit the elongatedmember from contacting the formation or a well casing (if the elongatedmember is placed within a well casing). The insulators may also inhibitlegs of the “U” shaped members from contacting each other. High aluminaceramic electrical insulators may be purchased from Cooper Industries(Houston, Tex.). In an embodiment, the “U” shaped member may be formedof different metals having different cross-sectional areas so that theelongated members may be relatively long and may dissipate a desiredamount of heat per unit length along the entire length of the elongatedmember.

[1110] Use of welded together sections may result in an elongated memberthat has large diameter sections near a top of the elongated member anda smaller diameter section or sections lower down a length of theelongated member. For example, an embodiment of an elongated member hastwo {fraction (7/8)} inch (2.2 cm) diameter first sections, two{fraction (1/2)} inch (1.3 cm) middle sections, and a 318 inch (0.95 cm)diameter bottom section that is bent into a “U” shape. The elongatedmember may be made of materials with other cross-sectional shapes suchas ovals, squares, rectangles, triangles, etc. The sections may beformed of alloys that will result in substantially the same heatdissipation per unit length for each section.

[1111] In some embodiments, the cross-sectional area and/or the metalused for a particular section may be chosen so that a particular sectionprovides greater (or lesser) heat dissipation per unit length than anadjacent section. More heat dissipation per unit length may be providednear an interface between a hydrocarbon layer and a non-hydrocarbonlayer (e.g., the overburden and the hydrocarbon layer) to counteract endeffects and allow for more uniform heat dissipation into the relativelypermeable formation. A higher heat dissipation may also be located at alower end of an elongated member to counteract end effects and allow formore uniform heat dissipation.

[1112] In certain embodiments, the wall thickness of portions of aconductor, or any electrically-conducting portion of a heater, may beadjusted to provide more or less heat to certain zones of a formation.In an embodiment, the wall thickness of a portion of the conductoradjacent to a lean zone (i.e., zone containing relatively little or nohydrocarbons) may be thicker than a portion of the conductor adjacent toa rich zone (i.e., hydrocarbon layer in which hydrocarbons are pyrolyzedand/or produced). Adjusting the wall thickness of a conductor to provideless heat to the lean zone and more heat to the rich zone may moreefficiently use electricity to heat the formation.

[1113]FIG. 94 illustrates a cross-sectional representation of anembodiment of a heater using two oxidizers. One or more oxidizers may beused to heat a hydrocarbon layer or hydrocarbon layers of a formationhaving a relatively shallow depth (e.g., less than about 250 m). Conduit6110 may be placed in opening 514 in a formation. Conduit 6110 may haveupper portion 6112. Upper portion 6112 of conduit 6110 may be placedprimarily in overburden 540 of the formation. A portion of conduit 6110may include high temperature resistant, non-corrosive materials (e.g.,316 stainless steel and/or 304 stainless steel). Upper portion 6112 ofconduit 6110 may include a less temperature resistant material (e.g.,carbon steel). A diameter of opening 514 and conduit 6110 may be chosensuch that a cross-sectional area of opening 514 outside of conduit 6110is approximately equal to a cross-sectional area inside conduit 6110.This may equalize pressures outside and inside conduit 6110. In anembodiment, conduit 6110 has a diameter of about 0.11 m and opening 514has a diameter of about 0.15 m.

[1114] Oxidizing fluid source 508 may provide oxidizing fluid 517 intoconduit 6110. Oxidizing fluid 517 may include hydrogen peroxide, air,oxygen, or oxygen enriched air. In an embodiment, oxidizing fluid source508 may include a membrane system that enriches air by preferentiallypassing oxygen, instead of nitrogen, through a membrane or membranes.First fuel source 6119 may provide fuel 6118 into first fuel conduit6116. First fuel conduit 6116 may be placed in upper portion 6112 ofconduit 6110. In some embodiments, first fuel conduit 6116 may be placedoutside conduit 6110. In other embodiments, conduit 6110 may be placedwithin first fuel conduit 6116. Fuel 6118 may include combustiblematerial, including but not limited to, hydrogen, methane, ethane, otherhydrocarbon fluids, and/or combinations thereof. Fuel 6118 may includesteam to inhibit coking within the fuel conduit or proximate anoxidizer. First oxidizer 6120 may be placed in conduit 6110 at a lowerend of upper portion 6112. First oxidizer 6120 may oxidize at least aportion of fuel 6118 from first fuel conduit 6116 with at least aportion of oxidizing fluid 517. First oxidizer may be a burner such asan inline burner. Burners may be obtained from John Zink Company (Tulsa,Okla.) or Callidus Technologies (Tulsa, Okla.). First oxidizer 6120 mayinclude an ignition source such as a flame. First oxidizer 6120 may alsoinclude a flameless ignition source such as, for example, an electricigniter.

[1115] In some embodiments, fuel 6118 and oxidizing fluid 517 may becombined at the surface and provided to opening 514 through conduit6110. Fuel 6118 and oxidizing fluid 517 may be combined in a mixer,aerator, nozzle, or similar mixing device located at the surface. Insuch an embodiment, conduit 6110 provides both fuel 6118 and oxidizingfluid 517 into opening 514. Locating first oxidizer 6120 at or proximatethe upper portion of the section of the formation to be heated may tendto inhibit or decrease coking in one or more of the fuel conduits (e.g.,in first fuel conduit 6116).

[1116] Oxidation of fuel 6118 at first oxidizer 6120 will generate heat.The generated heat may heat fluids in a region proximate first oxidizer6120. The heated fluids may include fuel, oxidizing fluid, and oxidationproducts. The heated fluids may be allowed to transfer heat tohydrocarbon layer 6100 along a length of conduit 6110. The amount ofheat transferred from the heated fluids to the formation may varydepending on, for example, a temperature of the heated fluids. Ingeneral, the greater the temperature of the heated fluids, the more heatthat will be transferred to the formation. In addition, as heat istransferred from the heated fluids, the temperature of the heated fluidsdecreases. For example, temperatures of fluids in the oxidizer flame maybe about 1300° C. or above, and as the fluids reach a distance of about150 m from the oxidizer, temperatures of fluids may be, for example,about 750° C. Thus, the temperature of the heated fluids, and hence theheat transferred to the formation, decreases as the heated fluids flowaway from the oxidizer.

[1117] First insulation 6122 may be placed on lengths of conduit 6110proximate a region of first oxidizer 6120. First insulation 6122 mayhave a length of about 10 m to about 200 m (e.g., about 50 m). Inalternative embodiments, first insulation 6122 may have a length that isabout 10-40% of the length of conduit 6110 between any two oxidizers(e.g., between first oxidizer 6120 and second oxidizer 6130 in FIG. 94).A length of first insulation 6122 may vary depending on, for example,desired heat transfer rate to the formation, desired temperatureproximate the first oxidizer, and/or desired temperature profile alongthe length of conduit 6110. First insulation 6122 may have a thicknessthat varies (either continually or in step fashion) along its length. Incertain embodiments, first insulation 6122 may have a greater thicknessproximate first oxidizer 6120 and a reduced thickness at a desireddistance from the first oxidizer. The greater thickness of firstinsulation 6122 may preferentially reduce heat transfer proximate firstoxidizer 6120 as compared to a reduced thickness portion of theinsulation. Variable thickness insulation may allow for uniform orrelatively uniform heating of the formation adjacent to a heated portionof the heat source. In an embodiment, first insulation 6122 may have athickness of about 0.03 m proximate first oxidizer 6120 and a thicknessof about 0.015 m at a distance of about 10 m from the first oxidizer. Inthe embodiment, the heated portion of the conduit is about 300 m inlength, with insulation (first insulation 6122) being placed proximatethe upper 100 m portion of this length, and insulation (secondinsulation 6132) being placed proximate the lower 100 m portion of thislength.

[1118] A thickness of first insulation 6122 may vary depending on, forexample, a desired heating rate or a desired temperature within opening514 of hydrocarbon layer 6100. The first insulation may inhibit thetransfer of heat from the heated fluids to the formation in a regionproximate the insulating conduit. First insulation 6122 may also inhibitcharring and/or coking of hydrocarbons proximate first oxidizer 6120.First insulation 6122 may inhibit charring and/or coking by reducing anamount of heat transferred to the formation proximate the firstoxidizer. First insulation 6122 may inhibit or decrease coking inconduit 6128 when a carbon containing fuel is in conduit 6128. Firstinsulation 6122 may be made of a non-corrosive, thermally insulatingmaterial such as rock wool, Nextel®, calcium silicate, Fiberfrax®,insulating refractory cements such as those manufactured by HarbizonWalker, A. P. Green, or National Refractories, etc. The relatively hightemperatures generated at the flame of first oxidizer 6120, which may beabout 1300° C. or greater, may generate sufficient heat to converthydrocarbons proximate the first oxidizer into coke and/or char if noinsulation is provided.

[1119] Heated fluids from conduit 6110 may exit a lower end of theconduit into opening 514. A temperature of the heated fluids may belower proximate the lower end of conduit 6110 than a temperature of theheated fluids proximate first oxidizer 6120. The heated fluids mayreturn to a surface of the formation through the annulus of opening 514(exhaust annulus 6124) and/or through exhaust conduit 6126. The heatedfluids exiting the formation through exhaust conduit 6126 may bereferred to as exhaust fluids. The exhaust fluids may be allowed tothermally contact conduit 6110 so as to exchange heat between exhaustfluids and either oxidizing fluid or fuel within conduit 6110. Thisexchange of heat may preheat fluids within conduit 6110. Thus, thethermal efficiency of the downhole combustor may be enhanced to as muchas 90% or more (i.e., 90% or more of the heat from the heat ofcombustion is being transferred to a selected section of the formation).

[1120] In certain embodiments, extra oxidizers may be used in additionto oxidizer 6120 and oxidizer 6130 shown in FIG. 94. For example, insome embodiments, one or more extra oxidizers may be placed betweenoxidizer 6120 and oxidizer 6130. Such extra oxidizers may be, forexample, placed at intervals of about 20-50 m. In certain embodiments,one oxidizer (e.g., oxidizer 6120) may provide at least about 50% of theheat to the selected section of the formation, and the other oxidizersmay be used to adjust the heat flux along the length of the oxidizer.

[1121] In some embodiments, fins may be placed on an outside surface ofconduit 6110 to increase exchange of heat between exhaust fluids andfluids within the conduit. Exhaust conduit 6126 may extend into opening514. A position of lower end of exhaust conduit 6126 may vary dependingon, for example, a desired removal rate of exhaust fluids from theopening. In certain embodiments, it may be advantageous to remove fluidsthrough exhaust conduit 6126 from a lower portion of opening 514 ratherthan allowing exhaust fluids to return to the surface through theannulus of the opening. All or part of the exhaust fluids may be vented,treated in a surface facility, and/or recycled. In some circumstances,the exhaust fluids may be recycled as a portion of fuel 6118 oroxidizing fluid 517 or recycled into an additional heater in anotherportion of the formation.

[1122] Two or more heater wells with oxidizers may be coupled in serieswith exhaust fluids from a first heater well being used as a portion offuel for a second heater well. Exhaust fluids from the second heaterwell may be used as a portion of fuel for a third heater well, and so onas needed. In some embodiments, a separator may separate unused fueland/or oxidizer from combustion products to increase the energy contentof the fuel for the next oxidizer. Using the heated exhaust fluids as aportion of the feed for a heater well may decrease costs associated withpressurizing fluids for use in the heater well. In an embodiment, aportion (e.g., about one-third or about one-half) of the oxygen in theoxidizing fluid stream provided to a first heater well may be utilizedin the first heater well. This would leave the remaining oxygenavailable for use as oxidizing fluid for subsequent heater wells. Theheated exhaust fluids tend to have a pressure associated with theprevious heater well and may be maintained at that pressure forproviding to the next heater well. Thus, connection of two or moreheater wells in series can significantly reduce compression costsassociated with pressurizing fluids.

[1123] Casing 541 and reinforcing material 544 may be placed inoverburden 540. Overburden 540 may be above hydrocarbon layer 6100. Incertain embodiments, casing 541 may extend downward into part or theentire zone being heated. Casing 541 may include steel (e.g., carbonsteel or stainless steel). Reinforcing material 544 may include, forexample, foamed cement or a cement with glass and/or ceramic beadsfilled with air.

[1124] As depicted in the embodiment of FIG. 94, a heater may havesecond fuel conduit 6128. Second fuel conduit 6128 may be coupled toconduit 6110. Second fuel source 6121 may provide fuel 6118 to secondfuel conduit 6128. Second fuel source 6121 may provide fuel that issimilar to fuel from first fuel source 6119. In some embodiments, fuelfrom second fuel source 6121 may be different than fuel from first fuelsource 6119. Fuel 6118 may exit second fuel conduit 6128 at a locationproximate second oxidizer 6130. Second oxidizer 6130 may be locatedproximate a bottom of conduit 6110 and/or opening 514. Second oxidizer6130 may be coupled to a lower end of second fuel conduit 6128. Secondoxidizer 6130 may be used to oxidize at least a portion of fuel 6118(exiting second fuel conduit 6128) with heated fluids exiting conduit6110. Un-oxidized portions of heated fluids from conduit 6110 may alsobe oxidized at second oxidizer 6130. Second oxidizer 6130 may be aburner (e.g., a ring burner). Second oxidizer 6130 may be made ofstainless steel. Second oxidizer 6130 may include one or more orificesthat allow a flow of fuel 6118 into opening 514. The one or moreorifices may be critical flow orifices. Oxidized portions of fuel 6118,along with un-oxidized portions of fuel, may combine with heated fluidsfrom conduit 6110 and exit the formation with the heated fluids. Heatgenerated by oxidation of fuel 6118 from second fuel conduit 6128proximate a lower end of opening 514, in combination with heat generatedfrom heated fluids in conduit 6110, may provide more uniform heating ofhydrocarbon layer 6100 than using a single oxidizer. In an embodiment,second oxidizer 6130 may be located about 200 m from first oxidizer6120. However, in some embodiments, second oxidizer 6130 may be locatedup to about 250 m from first oxidizer 6120.

[1125] Heat generated by oxidation of fuel at the first and secondoxidizers may be allowed to transfer to the formation. The generatedheat may transfer to a pyrolysis zone in the formation. Heat transferredto the pyrolysis zone may pyrolyze at least some hydrocarbons within thepyrolysis zone.

[1126] In some embodiments, ignition source 6134 may be disposedproximate a lower end of second fuel conduit 6128 and/or second oxidizer6130. Ignition source 6134 may be an electrically controlled ignitionsource. Ignition source 6134 may be coupled to ignition source lead-inwire 6136. Ignition source lead-in wire 6136 may be further coupled to apower source for ignition source 6134. Ignition source 6134 may be usedto initiate oxidation of fuel 6118 exiting second fuel conduit 6128.After oxidation of fuel 6118 from second fuel conduit 6128 has begun,ignition source 6134 may be turned down and/or off. In otherembodiments, an ignition source may also be disposed proximate firstoxidizer 6120.

[1127] In some embodiments, ignition source 6134 may not be used if, forexample, the conditions in the wellbore are sufficient to auto-ignitefuel 6118 being used. For example, if hydrogen is used as the fuel, thehydrogen will auto-ignite in the wellbore if the temperature andpressure in the wellbore are sufficient for autoignition of the fuel.

[1128] As shown in FIG. 94, second insulation 6132 may be disposed in aregion proximate second oxidizer 6130. Second insulation 6132 may bedisposed on a face of hydrocarbon layer 6100 along an inner surface ofopening 514. Second insulation 6132 may have a length of about 10 m toabout 200 m (e.g., about 50 m). A length of second insulation 6132 mayvary, however, depending on, for example, a desired heat transfer rateto the formation, a desired temperature proximate the lower oxidizer, ora desired temperature profile along a length of conduit 6110 and/orhydrocarbon layer 6100. In an embodiment, the length of secondinsulation 6132 is about 10-40% of the length of conduit 6110 betweenany two oxidizers. Second insulation 6132 may have a thickness thatvaries (either continually or in step fashion) along its length. Incertain embodiments, second insulation 6132 may have a larger thicknessproximate second oxidizer 6130 and a reduced thickness at a desireddistance from the second oxidizer. The larger thickness of secondinsulation 6132 may preferentially reduce heat transfer proximate secondoxidizer 6130 as compared to the reduced thickness portion of theinsulation. For example, second insulation 6132 may have a thickness ofabout 0.03 m proximate second oxidizer 6130 and a thickness of about0.015 m at a distance of about 10 m from the second oxidizer.

[1129] A thickness of second insulation 6132 may vary depending on, forexample, a desired heating rate or a desired temperature at a surface ofhydrocarbon layer 6100. The second insulation may inhibit the transferof heat from the heated fluids to the formation in a region proximatethe insulation. Second insulation 6132 may also inhibit charring and/orcoking of hydrocarbons proximate second oxidizer 6130. Second insulation6132 may inhibit charring and/or coking by reducing an amount of heattransferred to the formation proximate the second oxidizer. Secondinsulation 6132 may be made of a non-corrosive, thermally insulatingmaterial such as rock wool, Nextel™, calcium silicate, Fiberfrax®, orthermally insulating concretes such as those manufactured by HarbizonWalker, A. P. Green, or National Refractories. Hydrogen and/or steam mayalso be added to fuel used in the second oxidizer to further inhibitcoking and/or charring of the formation proximate the second oxidizerand/or fuel within the fuel conduit.

[1130] In other embodiments, one or more additional oxidizers may beplaced in opening 514. The one or more additional oxidizers may be usedto increase a heat output and/or provide more uniform heating of theformation. Additional fuel conduits and/or additional insulatingconduits may be used with the one or more additional oxidizers asneeded.

[1131] In an example using two downhole combustors to heat a portion ofa formation, the formation has a depth for treatment of about 228 m,with an overburden having a depth of about 91.5 m. Two oxidizers areused, as shown in the embodiment of FIG. 94, to provide heat to theformation in an opening with a diameter of about 0.15 m. To equalize thepressure inside the conduit and outside the conduit, a cross-sectionalarea inside the conduit should approximately equal a cross-sectionalarea outside the conduit. Thus, the conduit has a diameter of about 0.11m.

[1132] To heat the formation at a heat input of about 655 watts/meter(W/m), a total heat input of about 150,000 W is needed. About 16,000 Wof heat is generated for every 28 standard liters per minute (slm) ofmethane (CH₄) provided to the burners. Thus, a flow rate of about 270slm is needed to generate the 150,000 W of heat. A temperature midwaybetween the two oxidizers is about 555° C. less than the temperature ata flame of either oxidizer (about 1315° C.). The temperature midwaybetween the two oxidizers on the wall of the formation (where there isno insulation) is about 690° C. About 3,800 W can be carried by 2,830slm of air for every 55° C. of temperature change in the conduit. Thus,for the air to carry half the heat required (about 75,000 W) from thefirst oxidizer to the halfway point, 5,660 slm of air is needed. Theother half of the heat required may be supplied by air passing thesecond oxidizer and carrying heat from the second oxidizer.

[1133] Using air (21% oxygen) as the oxidizing fluid, a flow rate ofabout 5,660 slm of air can be used to provide excess oxygen to eachoxidizer. About half of the oxygen, or about 11% of the air, is used inthe two oxidizers in a first heater well. Thus, the exhaust fluid isessentially air with an oxygen content of about 10%. This exhaust fluidcan be used in a second heater well. Pressure of the incoming air of thefirst heater well is about 6.2 bars absolute. Pressure of the outgoingair of the first heater well is about 4.4 bars absolute. This pressureis also the incoming air pressure of a second heater well. The outletpressure of the second heater well is about 1.7 bars absolute. Thus, theair does not need to be recompressed between the first heater well andthe second heater well.

[1134]FIG. 95 illustrates a cross-sectional representation of anembodiment of a downhole combustor heater for heating a formation. Asdepicted in FIG. 95, electric heater 6140 may be used instead of secondoxidizer 6130 (as shown in FIG. 94) to provide additional heat to aportion of hydrocarbon layer 6100.

[1135] In a heat source embodiment, electric heater 6140 may be aninsulated conductor heater. In some embodiments, electric heater 6140may be a conductor-in-conduit heater or an elongated member heater. Ingeneral, electric heaters tend to provide a more controllable and/orpredictable heating profile than combustion heaters. The heat profile ofelectric heater 6140 may be selected to achieve a selected heatingprofile of the formation (e.g., uniform). For example, the heatingprofile of electric heater 6140 may be selected to “mirror” the heatingprofile of oxidizer 6120 such that, when the heat from electric heater6140 and oxidizer 6120 are superpositioned, substantially uniformheating is applied along the length of the conduit.

[1136] In other heat source embodiments, any other type of heater, suchas a natural distributed combustor or Blameless distributed combustor,may be used instead of electric heater 6140. In certain embodiments,electric heater 6140 may be used instead of first oxidizer 6120 to heata portion of hydrocarbon layer 6100. FIG. 96 depicts an embodiment usinga downhole combustor with a flameless distributed combustor. Second fuelconduit 6128 may have orifices 515 (e.g., critical flow orifices)distributed along the length of the conduit. Orifices 515 may bedistributed such that a heating profile along the length of hydrocarbonlayer 6100 is substantially uniform. For example, more orifices 515 maybe placed on second fuel conduit 6128 in a lower portion of the conduitthan in an upper portion of the conduit. This will provide more heatingto a portion of hydrocarbon layer 6100 that is farther from firstoxidizer 6120.

[1137] As depicted in FIG. 95, electric heater 6140 may be placed inopening 514 proximate conduit 6110. Electric heater 6140 may be used toprovide heat to hydrocarbon layer 6100 in a portion of opening 514proximate a lower end of conduit 6110. Electric heater 6140 may becoupled to lead-in conductor 6142. Using electric heater 6140 as well asheated fluids from conduit 6110 to heat hydrocarbon layer 6100 mayprovide substantially uniform heating of hydrocarbon layer 6100.

[1138]FIG. 97 illustrates a cross-sectional representation of anembodiment of a multilateral downhole combustor heater. Hydrocarbonlayer 6100 may be a relatively thin layer (e.g., with a thickness ofless than about 10 m, about 30 m, or about 60 m) selected for treatment.Opening 514 may extend below overburden 540 and then diverge in morethan one direction within hydrocarbon layer 6100. Opening 514 may havewalls that are substantially parallel to upper and lower surfaces ofhydrocarbon layer 6100.

[1139] Conduit 6110 may extend substantially vertically into opening 514as depicted in FIG. 97. First oxidizer 6120 may be placed in orproximate conduit 6110. Oxidizing fluid 517 may be provided to firstoxidizer 6120 through conduit 6110. First fuel conduit 6116 may be usedto provide fuel 6118 to first oxidizer 6120. Second conduit 6150 may becoupled to conduit 6110. Second conduit 6150 may be orientedsubstantially perpendicular to conduit 6110. Third conduit 6148 may alsobe coupled to conduit 6110. Third conduit 6148 may be orientedsubstantially perpendicular to conduit 6110. Second oxidizer 6130 may beplaced at an end of second conduit 6150. Second oxidizer 6130 may be aring burner. Third oxidizer 6144 may be placed at an end of thirdconduit 6148. In an embodiment, third oxidizer 6144 is a ring burner.Second oxidizer 6130 and third oxidizer 6144 may be placed at or nearopposite ends of opening 514.

[1140] Second fuel conduit 6128 may be used to provide fuel to secondoxidizer 6130. Third fuel conduit 6138 may be used to provide fuel tothird oxidizer 6144. Oxidizing fluid 517 may be provided to secondoxidizer 6130 through conduit 6110 and second conduit 6150. Oxidizingfluid 517 may be provided to third oxidizer 6144 through conduit 6110and third conduit 6148. First insulation 6122 may be placed proximatefirst oxidizer 6120. Second insulation 6132 and third insulation 6146may be placed proximate second oxidizer 6130 and third oxidizer 6144,respectively. Second oxidizer 6130 and third oxidizer 6144 may belocated up to about 175 m from first conduit 6110. In some embodiments,a distance between second oxidizer 6130 or third oxidizer 6144 and firstconduit 6110 may be less, depending on heating requirements ofhydrocarbon layer 6100. Heat provided by oxidation of fuel at firstoxidizer 6120, second oxidizer 6130, and third oxidizer 6144 may allowfor substantially uniform heating of hydrocarbon layer 6100.

[1141] Exhaust fluids may be removed through opening 514. The exhaustfluids may exchange heat with fluids entering opening 514 throughconduit 6110. Exhaust fluids may also be used in additional heater wellsand/or treated in surface facilities.

[1142] In a heat source embodiment, one or more electric heaters may beused instead of, or in combination with, first oxidizer 6120, secondoxidizer 6130, and/or third oxidizer 6144 to provide heat to hydrocarbonlayer 6100. Using electric heaters in combination with oxidizers mayprovide for substantially uniform heating of hydrocarbon layer 6100.

[1143]FIG. 98 depicts a heat source embodiment in which one or moreoxidizers are placed in first conduit 6160 and second conduit 6162 toprovide heat to hydrocarbon layer 6100. The embodiment may be used toheat a relatively thin formation. First oxidizer 6120 may be placed infirst conduit 6160. A second oxidizer 6130 may be placed proximate anend of first conduit 6160. First fuel conduit 6116 may provide fuel tofirst oxidizer 6120. Second fuel conduit 6128 may provide fuel to secondoxidizer 6130. First insulation 6122 may be placed proximate firstoxidizer 6120. Oxidizing fluid 517 may be provided into first conduit6160. A portion of oxidizing fluid 517 may be used to oxidize fuel atfirst oxidizer 6120. Second insulation may be placed proximate secondoxidizer 6130.

[1144] Second conduit 6162 may diverge in an opposite direction fromfirst conduit 6160 in opening 514 and substantially mirror first conduit6160. Second conduit 6162 may include elements similar to the elementsof first conduit 6160, such as first oxidizer 6120, first fuel conduit6116, first insulation 6122, second oxidizer 6130, second fuel conduit6128, and/or second insulation 6132. These elements may be used tosubstantially uniformly heat hydrocarbon layer 6100 below overburden 540along lengths of conduits 6160 and 6162.

[1145]FIG. 99 illustrates a cross-sectional representation of anembodiment of a downhole combustor for heating a formation. Opening 514is a single opening within hydrocarbon layer 6100 that may have firstend 6170 and second end 6172. Oxidizers 6120 may be placed in opening514 proximate a junction of overburden 540 and hydrocarbon layer 6100 atfirst end 6170 and second end 6172. Insulation 6132 may be placedproximate each oxidizer 6120. Fuel conduit 6116 may be used to providefuel 6118 from fuel source 6119 to oxidizer 6120. Oxidizing fluid 517may be provided into opening 514 from oxidizing fluid source 508 throughconduit 6110. Casing 6152 may be placed in opening 514. Casing 6152 maybe made of carbon steel. Portions of casing 6152 that may be subjectedto much higher temperatures (e.g., proximate oxidizers 6120) may includestainless steel or other high temperature, corrosion resistant metal. Insome embodiments, casing 6152 may extend into portions of opening 514within overburden 540.

[1146] In a heat source embodiment, oxidizing fluid 517 and fuel 6118are provided to oxidizer 6120 in first end 6170. Heated fluids fromoxidizer 6120 in first end 6170 tend to flow through opening 514 towardssecond end 6172. Heat may transfer from the heated fluids to hydrocarbonlayer 6100 along a length of opening 514. The heated fluids may beremoved from the formation through second end 6172. During this time,oxidizer 6120 at second end 6172 may be turned off. The removed fluidsmay be provided to a second opening in the formation and used asoxidizing fluid and/or fuel in the second opening. After a selected time(e.g., about a week), oxidizer 6120 at first end 6170 may be turned off.At this time, oxidizing fluid 517 and fuel 6118 may be provided tooxidizer 6120 at second end 6172 and the oxidizer turned on. Heatedfluids may be removed during this time through first end 6170. Oxidizers6120 at first end 6170 and at second end 6172 may be used alternatelyfor selected times (e.g., about a week) to heat hydrocarbon layer 6100.This may provide a more substantially uniform heating profile ofhydrocarbon layer 6100. Removing the heated fluids from the openingthrough an end distant from an oxidizer may reduce a possibility ofcoking within opening 514 as heated fluids are removed from the openingseparately from incoming fluids: The use of the heat content of anoxidizing fluid may also be more efficient as the heated fluids can beused in a second opening or second downhole combustor.

[1147]FIG. 100 depicts an embodiment of a heat source for a relativelypermeable formation. Fuel conduit 6116 may be placed within opening 514.In some embodiments, opening 514 may include casing 6152. Opening 514 isa single opening within the formation that may have first end 6170 at afirst location on the surface of the earth and second end 6172 at asecond location on the surface of the earth. Oxidizers 6120 may bepositioned proximate the fuel conduit in hydrocarbon layer 516.Oxidizers 6120 may be separated by a distance ranging from about 3 m toabout 50 m (e.g., about 30 m). Fuel 6118 may be provided to fuel conduit6116. In addition, steam 9674 may be provided to fuel conduit 6116 toreduce coking proximate oxidizers 6120 and/or in fuel conduit 6116.Oxidizing fluid 6110 (e.g., air and/or oxygen) may be provided tooxidizers 6120 through opening 514. Oxidation of fuel 6118 may generateheat. The heat may transfer to a portion of the formation. Oxidationproducts 9676 may exit opening 514 proximate second location 6172.

[1148]FIG. 101 depicts a schematic, from an elevated view, of anembodiment for using downhole combustors depicted in the embodiment ofFIG. 99. Openings 6180, 6182, 6184, 6186, 6188, and 6190 may havedownhole combustors (as shown in the embodiment of FIG. 99) placed ineach opening. More or fewer openings (i.e., openings with a downholecombustor) may be used as needed. A number of openings may depend on,for example, a size of an area for treatment, a desired heating rate, ora selected well spacing. Conduit 6196 may be used to transport fluidsfrom a downhole combustor in opening 6180 to downhole combustors inopenings 6182, 6184, 6186, 6188, and 6190. The openings may be coupledin series using conduit 6196. Compressor 6192 may be used betweenopenings, as needed, to increase a pressure of fluid between theopenings. Additional oxidizing fluid may be provided to each compressor6192 from conduit 6194. A selected flow of fuel from a fuel source maybe provided into each of the openings.

[1149] For a selected time, a flow of fluids may be from first opening6180 towards opening 6190. Flow of fluid within first opening 6180 maybe substantially opposite flow within second opening 6182. Subsequently,flow within second opening 6182 may be substantially opposite flowwithin third opening 6184, etc. This may provide substantially moreuniform heating of the formation using the downhole combustors withineach opening. After the selected time, the flow of fluids may bereversed to flow from opening 6190 towards first opening 6180. Thisprocess may be repeated as needed during a time needed for treatment ofthe formation. Alternating the flow of fluids may enhance the uniformityof a heating profile of the formation.

[1150]FIG. 102 depicts a schematic representation of an embodiment of aheater well positioned within a relatively permeable formation. Heaterwell 6230 may be placed within opening 514. In certain embodiments,opening 514 is a single opening within the formation that may have firstend 6170 and second end 6172 contacting the surface of the earth.Opening 514 may include elongated portions 9630, 9632, 9634. Elongatedportions 9630, 9634 may be placed substantially in a non-hydrocarboncontaining layer (e.g., overburden). Elongated portion 9632 may beplaced substantially within hydrocarbon layer 6100 and/or a treatmentzone.

[1151] In some heat source embodiments, casing 6152 may be placed inopening 514. In some embodiments, casing 6152 may be made of carbonsteel. Portions of casing 6152 that may be subjected to hightemperatures may be made of more temperature resistant material (e.g.,stainless steel). In some embodiments, casing 6152 may extend intoelongated portions 9630, 9634 within overburden 540. Oxidizers 6120,6130 may be placed proximate a junction of overburden 540 andhydrocarbon layer 6100 at first end 6170 and second end 6172 of opening514. Oxidizers 6120, 6130 may include burners (e.g., inline burnersand/or ring burners). Insulation 6132 may be placed proximate eachoxidizer 6120, 6130.

[1152] Conduit 9620 may be placed within opening 514 forming annulus9621 between an outer surface of conduit 9620 and an inner surface ofthe casing 6152. Annulus 9621 may have a regular and/or irregular shapewithin the opening. In some embodiments, oxidizers may be positionedwithin the annulus and/or the conduit to provide heat to a portion ofthe formation. Oxidizer 6120 is positioned within annulus 9621 and mayinclude a ring burner. Heated fluids from oxidizer 6120 may flow withinannulus 9621 to end 6172. Heated fluids from oxidizer 6130 may bedirected by conduit 9620 through opening 514. Heated fluids may include,but are not limited to oxidation products, oxidizing fluid, and/or fuel.Flow of the heated fluids through annulus 9621 may be in the oppositedirection of the flow of heated fluids in conduit 9620. In alternateembodiments, oxidizers 6120, 6130 may be positioned proximate the sameend of opening 514 to allow the heated fluids to flow through opening514 in the same direction.

[1153] Fuel conduits 6116 may be used to provide fuel 6118 from fuelsource 6119 to oxidizers 6120, 6130. Oxidizing fluid 517 may be providedto oxidizers 6120, 6130 from oxidizing fluid source 508 through conduits6110. Flow of fuel 6118 and oxidizing fluid 517 may generate oxidationproducts at oxidizers 6120, 6130. In some embodiments, a flow ofoxidizing fluid 517 may be controlled to control oxidation at oxidizers6120, 6130. Alternatively, a flow of fuel may be controlled to controloxidation at oxidizers 6120, 6130.

[1154] In a heat source embodiment, oxidizing fluid 517 and fuel 6118are provided to oxidizer 6120. Heated fluids from oxidizer 6120 in firstend 6170 tend to flow through opening 514 towards second end 6172. Heatmay transfer from the heated fluids to hydrocarbon layer 6100 along asegment of opening 514. The heated fluids may be removed from theformation through second end 6172. In some embodiments, a portion of theheated fluids removed from the formation may be provided to fuel conduit6116 at end 6172 to be utilized as fuel in oxidizer 6130. Fluids heatedby oxidizer 6130 may be directed through the opening in conduit 9620 tofirst end 6170. In some embodiments, a portion of the heated fluids isprovided to fuel conduit 6116 at first end 6170. Alternatively, heatedfluids produced from either end of the opening may be directed to asecond opening in the formation for use as either oxidizing fluid and/orfuel. In some embodiments, heated fluids may be directed toward one endof the opening for use in a single oxidizer.

[1155] Oxidizers 6120, 6130 may be utilized concurrently. In someembodiments, use of the oxidizers may alternate. Oxidizer 6120 may beturned off after a selected time period (e.g., about a week). At thistime, oxidizing fluid 517 and fuel 6118 may be provided to oxidizer6130. Heated fluids may be removed during this time through first end6170. Use of oxidizer 6120 and oxidizer 6130 may be alternated forselected times to heat hydrocarbon layer 6100. Flowing oxidizing fluidsin opposite directions may produce a more uniform heating profile inhydrocarbon layer 6100. Removing the heated fluids from the openingthrough an end distant from the oxidizer at which the heated fluids wereproduced may reduce the possibility for coking within the opening.Heated fluids may be removed from the formation in exhaust conduits insome embodiments. In addition, the potential for coking may be furtherreduced by removing heated fluids from the opening separately fromincoming fluids (e.g., fuel and/or oxidizing fluid). In certaininstances, some heat within the heated fluids may transfer to theincoming fluids to increase the efficiency of the oxidizers.

[1156]FIG. 103 depicts an embodiment of a heat source positioned withina relatively permeable formation. Surface units 9672 (e.g., burnersand/or furnaces) provide heat to an opening in the formation. Surfaceunit 9672 may provide heat to conduit 9620 positioned in conduit 9622.Surface unit 9672 positioned proximate first end 6170 of opening 514 mayheat fluids 9670 (e.g., air, oxygen, steam, fuel, and/or flue gas)provided to surface unit 9672. Conduit 9620 may extend into surface unit9672 to allow fluids heated in surface unit 9672 proximate first end6170 to flow into conduit 9620. Conduit 9620 may direct fluid flow tosecond end 6172. At second end 6172 conduit 9620 may provide fluids tosurface unit 9672. Surface unit 9672 may heat the fluids. The heatedfluids may flow into conduit 9622. Heated fluids may then flow throughconduit 9622 towards end 6170. In some embodiments, conduit 9620 andconduit 9622 may be concentric.

[1157] In alternate embodiments, fluids may be compressed prior toentering the surface unit. Compression of the fluids may maintain afluid flow through the opening. Flow of fluids through the conduits mayaffect the transfer of heat from the conduits to the formation.

[1158] In alternate embodiments, a single surface unit may be utilizedfor heating proximate first end 6170. Conduits may be positioned suchthat fluid within an inner conduit flows into the annulus between theinner conduit and an outer conduit. Thus the fluid flow in the innerconduit and the annulus may be counter current.

[1159] A heat source embodiment is illustrated in FIG. 104. Conduits9620, 9622 may be placed within opening 514. Opening 514 may be an openwellbore. In alternate embodiments, a casing may be included in aportion of the opening (e.g., in the portion in the overburden). Inaddition, some embodiments may include insulation surrounding a portionof conduits 9620, 9622. For example, the portions of the conduits withinoverburden 540 may be insulated to inhibit heat transfer from the heatedfluids to the overburden and/or a portion of the formation proximate theoxidizers.

[1160]FIG. 105 illustrates an embodiment of a surface combustor that mayheat a section of a relatively permeable formation. Fuel fluid 611 maybe provided into burner 610 through conduit 617. An oxidizing fluid maybe provided into burner 610 from oxidizing fluid source 508. Fuel fluid611 may be oxidized with the oxidizing fluid in burner 610 to formoxidation products 613. Fuel fluid 611 may include, but is not limitedto, hydrogen, methane, ethane, and/or other hydrocarbons. Burner 610 maybe located external to the formation or within opening 614 inhydrocarbon layer 516. Source 618 may heat fuel fluid 611 to atemperature sufficient to support oxidation in burner 610. Source 618may heat fuel fluid 611 to a temperature of about 1425° C. Source 618may be coupled to an end of conduit 617. In a heat source embodiment,source 618 is a pilot flame. The pilot flame may burn with a small flowof fuel fluid 611. In other embodiments, source 618 may be an electricalignition source.

[1161] Oxidation products 613 may be provided into opening 614 withininner conduit 612 coupled to burner 610. Heat may be transferred fromoxidation products 613 through outer conduit 615 into opening 614 and tohydrocarbon layer 516 along a length of inner conduit 612. Oxidationproducts 613 may cool along the length of inner conduit 612. Forexample, oxidation products 613 may have a temperature of about 870° C.proximate top of inner conduit 612 and a temperature of about 650° C.proximate bottom of inner conduit 612. A section of inner conduit 612proximate burner 610 may have ceramic insulator 612 b disposed on aninner surface of inner conduit 612. Ceramic insulator 612 b may inhibitmelting of inner conduit 612 and/or insulation 612 a proximate burner610. Opening 614 may extend into the formation a length up to about 550m below surface 550.

[1162] Inner conduit 612 may provide oxidation products 613 into outerconduit 615 proximate a bottom of opening 614. Inner conduit 612 mayhave insulation 612 a. FIG. 106 illustrates an embodiment of innerconduit 612 with insulation 612 a and ceramic insulator 612 b disposedon an inner surface of inner conduit 612. Insulation 612 a may inhibitheat transfer between fluids in inner conduit 612 and fluids in outerconduit 615. A thickness of insulation 612 a may be varied along alength of inner conduit 612 such that heat transfer to hydrocarbon layer516 may vary along the length of inner conduit 612. For example, athickness of insulation 612 a may be tapered from a larger thickness toa lesser thickness from a top portion to a bottom portion, respectively,of inner conduit 612 in opening 614. Such a tapered thickness mayprovide more uniform heating of hydrocarbon layer 516 along the lengthof inner conduit 612 in opening 614. Insulation 612 a may includeceramic and metal materials. Oxidation products 613 may return tosurface 550 through outer conduit 615. Outer conduit may have insulation615 a, as depicted in FIG. 105. Insulation 615 a may inhibit heattransfer from outer conduit 615 to overburden 540.

[1163] Oxidation products 613 may be provided to an additional burnerthrough conduit 619 at surface 550. Oxidation products 613 may be usedas a portion of a fuel fluid in the additional burner. Doing so mayincrease an efficiency of energy output versus energy input for heatinghydrocarbon layer 516. The additional burner may provide heat through anadditional opening in hydrocarbon layer 516.

[1164] In some embodiments, an electric heater may provide heat inaddition to heat provided from a surface combustor. The electric heatermay be, for example, an insulated conductor heater or aconductor-in-conduit heater as described in any of the aboveembodiments. The electric heater may provide the additional heat to arelatively permeable formation so that the relatively permeableformation is heated substantially uniformly along a depth of an openingin the formation.

[1165] Flameless combustors such as those described in U.S. Pat. No.5,404,952 to Vinegar et al., which is incorporated by reference as iffully set forth herein, may heat a relatively permeable formation.

[1166]FIG. 107 illustrates an embodiment of a flameless combustor thatmay heat a section of the relatively permeable formation. The flamelesscombustor may include center tube 637 disposed within inner conduit 638.Center tube 637 and inner conduit 638 may be placed within outer conduit636. Outer conduit 636 may be disposed within opening 514 in hydrocarbonlayer 516. Fuel fluid 621 may be provided into the flameless combustorthrough center tube 637. If a hydrocarbon fuel such as methane isutilized, the fuel may be mixed with steam to inhibit coking in centertube 637. If hydrogen is used as the fuel, no steam may be required.

[1167] Center tube 637 may include flow mechanisms 635 (e.g., floworifices) disposed within an oxidation region to allow a flow of fuelfluid 621 into inner conduit 638. Flow mechanisms 635 may control a flowof fuel fluid 621 into inner conduit 638 such that the flow of fuelfluid 621 is not dependent on a pressure in inner conduit 638. Oxidizingfluid 623 may be provided into the combustor through inner conduit 638.Oxidizing fluid 623 may be provided from oxidizing fluid source 508.Flow mechanisms 635 on center tube 637 may inhibit flow of oxidizingfluid 623 into center tube 637.

[1168] Oxidizing fluid 623 may mix with fuel fluid 621 in the oxidationregion of inner conduit 638. Either oxidizing fluid 623 or fuel fluid621, or a combination of both, may be preheated external to thecombustor to a temperature sufficient to support oxidation of fuel fluid621. Oxidation of fuel fluid 621 may provide heat generation withinouter conduit 636. The generated heat may provide heat to a portion of arelatively permeable formation proximate the oxidation region of innerconduit 638. Products 625 from oxidation of fuel fluid 621 may beremoved through outer conduit 636 outside inner conduit 638. Heatexchange between the downgoing oxidizing fluid and the upgoingcombustion products in the overburden results in enhanced thermalefficiency. A flow of removed combustion products 625 may be balancedwith a flow of fuel fluid 621 and oxidizing fluid 623 to maintain atemperature above auto-ignition temperature but below a temperaturesufficient to produce oxides of nitrogen. In addition, a constant flowof fluids may provide a substantially uniform temperature distributionwithin the oxidation region of inner conduit 638. Outer conduit 636 maybe a stainless steel tube. Heating in the portion of the relativelypermeable formation may be substantially uniform. Maintaining atemperature below temperatures sufficient to produce oxides of nitrogenmay allow for relatively inexpensive metallurgical cost.

[1169] Care may be taken during design and installation of a well (e.g.,freeze wells, production wells, monitoring wells, and heat sources) intoa formation to allow for thermal effects within the formation. Heatingand/or cooling of the formation may expand and/or contract elements of awell, such as the well casing. Elements of a well may expand or contractat different rates (e.g., due to different thermal expansioncoefficients). Thermal expansion or contraction may cause failures (suchas leaks, fractures, short-circuiting, etc.) to occur in a well. Anoperational lifetime of one or more elements in the wellbore may beshortened by such failures.

[1170] In some well embodiments, a portion of the well is an openwellbore completion. Portions of the well may be suspended from awellbore or a casing that is cemented in the formation (e.g., a portionof a well in the overburden). Expansion of the well due to heat may beaccommodated in the open wellbore portion of the well.

[1171] In a well embodiment, an expansion mechanism may be coupled to aheat source or other element of a well placed in an opening in aformation. The expansion mechanism may allow for thermal expansion ofthe heat source or element during use. The expansion mechanism may beused to absorb changes in length of the well as the well expands orcontracts with temperature. The expansion mechanism may inhibit the heatsource or element from being pushed out of the opening during thermalexpansion. Using the expansion mechanism in the opening may increase anoperational lifetime of the well.

[1172]FIG. 108 illustrates a representation of an embodiment ofexpansion mechanism 6012 coupled to heat source 8682 in opening 514 inhydrocarbon layer 516. Expansion mechanism 6012 may allow for thermalexpansion of heat source 8682. Heat source 8682 may be any heat source(e.g., conductor-in-conduit heat source, insulated conductor heatsource, natural distributed combustor heat source, etc.). In someembodiments, more than one expansion mechanism 6012 may be coupled toindividual components of a heat source. For example, if the heat sourceincludes more than one element (e.g., conductors, conduits, supports,cables, elongated members, etc.), an expansion mechanism may be coupledto each element. Expansion mechanism 6012 may include spring loading. Inone embodiment, expansion mechanism 6012 is an accordion mechanism. Inanother embodiment, expansion mechanism 6012 is a bellows or anexpansion joint.

[1173] Expansion mechanism 6012 may be coupled to heat source 8682 at abottom of the heat source in opening 514. In some embodiments, expansionmechanism 6012 may be coupled to heat source 8682 at a top of the heatsource. In other embodiments, expansion mechanism 6012 may be placed atany point along the length of heat source 8682 (e.g., in a middle of theheat source). Expansion mechanism 6012 may be used to reduce the hangingweight of heat source 8682 (i.e., the weight supported by a wellheadcoupled to the heat source). Reducing the hanging weight of heat source8682 may reduce creeping of the heat source during heating.

[1174] Certain heat source embodiments may include an operating systemcoupled to a heat source or heat sources by insulated conductors orother types of wiring. The operating system may interface with the heatsource. The operating system may receive a signal (e.g., anelectromagnetic signal) from a heater that is representative of atemperature distribution of the heat source. Additionally, the operatingsystem may control the heat source, either locally or remotely. Forexample, the operating system may alter a temperature of the heat sourceby altering a parameter of equipment coupled to the heat source. Theoperating system may monitor, alter, and/or control the heating of atleast a portion of the formation.

[1175] For some heat source embodiments, a heat source or heat sourcesmay operate without a control and/or operating system. A heat source mayonly require a power supply from a power source such as an electrictransformer. A conductor-in-conduit heater and/or an elongated memberheater may include a heater element formed of a self-regulatingmaterial, such as 304 stainless steel or 316 stainless steel. Powerdissipation and amperage through a heater element made of aself-regulating material decrease as temperature increases, and increaseas temperature decreases due in part to the resistivity properties ofthe material and Ohm's Law. For a substantially constant voltage supplyto a heater element, if the temperature of the heater element increases,the resistance of the element will increase, the amperage through theheater element will decrease, and the power dissipation will decrease;thus forcing the heater element temperature to decrease. On the otherhand, if the temperature of the heater element decreases, the resistanceof the element will decrease, the amperage through the heater elementwill increase, and the power dissipation will increase; thus forcing theheater element temperature to increase. Some metals, such as certaintypes of nichrome, have resistivity curves that decrease with increasingtemperature for certain temperature ranges. Such materials may not becapable of being self-regulating heaters.

[1176] In some heat source embodiments, leakage current of electricheaters may be monitored. For insulated heaters, an increase in leakagecurrent may show deterioration in an insulated conductor heater. Voltagebreakdown in the insulated conductor heater may cause failure of theheat source. In some heat source embodiments, a current and voltageapplied to electric heaters may be monitored. The current and voltagemay be monitored to assess/indicate resistance in a heater element ofthe heat source. The resistance in the heat source may represent atemperature in the heat source since the resistance of the heat sourcemay be known as a function of temperature. In some embodiments, atemperature of a heat source may be monitored with one or morethermocouples placed in or proximate the heat source. In someembodiments, a control system may monitor a parameter of the heatsource. The control system may alter parameters of the heat source toestablish a desired output such as heating rate and/or temperatureincrease.

[1177] In some embodiments, a thermowell may be disposed into an openingin a relatively permeable formation that includes a heat source. Thethermowell may be disposed in an opening that may or may not have acasing. In the opening without a casing, the thermowell may includeappropriate metallurgy and thickness such that corrosion of thethermowell is inhibited. A thermowell and temperature logging process,such as that described in U.S. Pat. No. 4,616,705 issued to Stegemeieret al., which is incorporated by reference as if fully set forth herein,may be used to monitor temperature. Only selected wells may be equippedwith thermowells to avoid expenses associated with installing andoperating temperature monitors at each heat source. Some thermowells maybe placed midway between two heat sources. Some thermowells may beplaced at or close to a center of a well pattern. Some thermowells maybe placed in or adjacent to production wells.

[1178] In an embodiment for treating a relatively permeable formation insitu, an average temperature within a majority of a selected section ofthe formation may be assessed by measuring temperature within a wellboreor wellbores. The wellbore may be a production well, heater well, ormonitoring well. The temperature within a wellbore may be measured tomonitor and/or determine operating conditions within the selectedsection of the formation. The measured temperature may be used as aproperty for input into a program for controlling production within theformation. In certain embodiments, a measured temperature may be used asinput for a software executable on a computational system. In someembodiments, a temperature within a wellbore may be measured using amoveable thermocouple. The moveable thermocouple may be disposed in aconduit of a heater or heater well. An example of a moveablethermocouple and its use is described in U.S. Pat. No. 4,616,705 toStegemeier et al.

[1179] In an alternate embodiment, more than one thermocouple may beplaced in a wellbore to measure the temperature within the wellbore. Thethermocouples may be part of a multiple thermocouple array. Thethermocouples may be located at various depths and/or locations. Themultiple thermocouple array may include a magnesium oxide insulatedsheath or sheaths placed around portions of the thermocouples. Theinsulated sheaths may include corrosion resistant materials. A corrosionresistant material may include, but is not limited to, stainless steels304, 310, 316 or Inconel. Multiple thermocouple arrays may be obtainedfrom Pyrotenax Cables Ltd. (Ontario, Canada) or Idaho Labs (Idaho Falls,Id.). The multiple thermocouple array may be moveable within thewellbore.

[1180] In certain thermocouple embodiments, voltage isolation may beused with a moveable thermocouple placed in a wellbore. FIG. 109illustrates a schematic of thermocouple 9202 placed inside conductor580. Conductor 580 may be placed within conduit 582 of aconductor-in-conduit heat source. Conductor 580 may be coupled to lowresistance section 584. Low resistance section 584 may be placed inoverburden 540. Conduit 582 may be placed in wellbore 9206. Thermocouple9202 may be used to measure a temperature within conductor 580 along alength of the conductor in hydrocarbon layer 516. Thermocouple 9202 mayinclude thermocouple wires that are coupled at the surface to spool 9208so that the thermocouple is moveable along the length of conductor 580to obtain a temperature profile in the heated section. Thermocoupleisolation 9204 may be coupled to thermocouple 9202. Thermocoupleisolation 9204 may be, for example, a transformer coupled thermocoupleisolation block available from Watlow Electric Manufacturing Company(St. Louis, Mo.). Alternately, an optically isolated thermocoupleisolation block may be used. Thermocouple isolation 9204 may reducevoltages above the thermocouple isolation and at wellhead 690. Highvoltages may exist within wellbore 9206 due to use of the electric heatsource within the wellbore. The high voltages can be dangerous foroperators or personnel working around wellhead 690. With thermocoupleisolation 9204, voltages at wellhead 690 (e.g., at spool 9208) may belowered to safer levels (e.g., about zero or ground potential). Thus,using thermocouple isolation 9204 may increase safety at wellhead 690.

[1181] In some embodiments, thermocouple isolation 9204 may be usedalong the length of low resistance section 584. Temperatures within lowresistance section 584 may not be above a maximum operating temperatureof thermocouple isolation 9204. Thermocouple isolation 9204 may be movedalong the length of low resistance section 584 as thermocouple 9202 ismoved along the length of conductor 580 by spool 9208. In otherembodiments, thermocouple isolation 9204 may be placed at wellhead 690.

[1182] In a temperature monitor embodiment, a temperature within awellbore in a formation is measured using a fiber assembly. The fiberassembly may include optical fibers made from quartz or glass. The fiberassembly may have fibers surrounded by an outer shell. The fibers mayinclude fibers that transmit temperature measurement signals. A fiberthat may be used for temperature measurements can be obtained from SensaHighway (Houston, Tex.). The fiber assembly may be placed within awellbore in the formation. The wellbore may be a heater well, amonitoring well, or a production well. Use of the fibers may be limitedby a maximum temperature resistance of the outer shell, which may beabout 800° C. in some embodiments. A signal may be sent down a fiberdisposed within a wellbore. The signal may be a signal generated by alaser or other optical device. Thermal noise may be developed in thefiber from conditions within the wellbore. The amount of noise may berelated to a temperature within the wellbore. In general, the more noiseon the fiber, the higher the temperature within the wellbore. This maybe due to changes in the index of refraction of the fiber as thetemperature of the fiber changes. The relationship between noise andtemperature may be characterized for a certain fiber. This relationshipmay be used to determine a temperature of the fiber along the length ofthe fiber. The temperature of the fiber may represent a temperaturewithin the wellbore.

[1183] In some in situ conversion process embodiments, a temperaturewithin a wellbore in a formation may be measured using pressure waves. Apressure wave may include a sound wave. Examples of using sound waves tomeasure temperature are shown in U.S. Pat. Nos. 5,624,188 to West,5,437,506 to Gray, 5,349,859 to Kleppe, 4,848,924 to Nuspl et al.,4,762,425 to Shakkottai et al., and 3,595,082 to Miller, Jr., which areincorporated by reference as if fully set forth herein. Pressure wavesmay be provided into the wellbore. The wellbore may be a heater well, aproduction well, a monitoring well, or a test well. A test well may be awell placed in a formation that is used primarily for measurement ofproperties of the formation. A plurality of discontinuities may beplaced within the wellbore. A predetermined spacing may exist betweeneach discontinuity. The plurality of discontinuities may be placedinside a conduit placed within a wellbore. For example, the plurality ofdiscontinuities may be placed within a conduit used as a portion of aconductor-in-conduit heater or a conduit used to provide fluid into awellbore. The plurality of discontinuities may also be placed on anexternal surface of a conduit in a wellbore. A discontinuity mayinclude, but may not be limited to, an alumina centralizer, a stub, anode, a notch, a weld, a collar, or any such point that may reflect apressure wave.

[1184]FIG. 110 depicts a schematic view of an embodiment for usingpressure waves to measure temperature within a wellbore. Conduit 6350may be placed within wellbore 6352. Plurality of discontinuities 6354may be placed within conduit 6350. The discontinuities may be separatedby substantially constant separation distance 6356. Distance 6356 maybe, in some embodiments, about 1 m, about 5 m, or about 15 m. A pressurewave may be provided into conduit 6350 from pressure wave source 6358.Pressure wave source 6358 may include, but is not limited to, an airgun, an explosive device (e.g., blank shotgun), a piezoelectric crystal,a magnetostrictive transducer, an electrical sparker, or a compressedair source. A compressed air source may be operated or controlled by asolenoid valve. The pressure wave may propagate through conduit 6350. Insome embodiments, an acoustic wave may be propagated through the wall ofthe conduit.

[1185] A reflection (or signal) of the pressure wave within conduit 6350may be measured using wave measuring device 6363. Wave measuring device6363 may be, for example, a piezoelectric crystal, a magnetostrictivetransducer, or any device that measures a time-domain pressure of thewave within the conduit. Wave measuring device 6363 may determinetime-domain pressure wave 6360 that represents travel of the pressurewave within conduit 6350. Each slight increase in pressure, or pressurespike 6362, represents a reflection of the pressure wave at adiscontinuity 6354. The pressure wave may be repeatedly provided intothe wellbore at a selected frequency. The reflected signal may becontinuously measured to increase a signal-to-noise ratio for pressurespike 6362 in the reflected signal. This may include using a repetitivestacking of signals to reduce noise. A repeatable pressure wave sourcemay be used. For example, repeatable signals may be producible from apiezoelectric crystal. A trigger signal may be used to start wavemeasuring device 6363 and pressure wave source 6358. The time, asmeasured using pressure wave 6360, may be used with the distance betweeneach discontinuity 6356 to determine an average temperature between thediscontinuities for a known gas within conduit 6350. Since the velocityof the pressure wave varies with temperature within conduit 6350, thetime for travel of the pressure wave between discontinuities will varywith an average temperature between the discontinuities. For dry airwithin a conduit or wellbore, the temperature may be approximated usingthe equation:

c=33,145×(1+T/273.16)^(1/2);  (19)

[1186] in which c is the velocity of the wave in cm/sec and T is thetemperature in degrees Celsius. If the gas includes other gases or amixture of gases, EQN. 19 can be modified to incorporate properties ofthe alternate gas or the gas mixture. EQN. 19 can be derived from themore general equation for the velocity of a wave in a gas:

c=[(RT/M)(1+R/C _(v))]^(1/2);  (20)

[1187] in which R is the ideal gas constant, T is the temperature inKelvin, and C_(v) is the heat capacity of the gas.

[1188] Alternatively, a reference time-domain pressure wave can bedetermined at a known ambient temperature. Thus, a time-domain pressurewave determined at an increased temperature within the wellbore may becompared to the reference pressure wave to determine an averagetemperature within the wellbore after heating the formation. The changein velocity between the reference pressure wave and the increasedtemperature pressure wave, as measured by the change in distance betweenpressure spikes 6362, can be used to determine the increased temperaturewithin the conduit. Use of pressure waves to measure an averagetemperature may require relatively low maintenance. Using the velocityof pressure waves to measure temperature may be less expensive thanother temperature measurement methods.

[1189] In some embodiments, a heat source may be turned down and/or offafter an average temperature in a formation reaches a selectedtemperature. Turning down and/or off the heat source may reduce inputenergy costs, inhibit overheating of the formation, and allow heat totransfer into colder regions of the formation.

[1190] In some in situ conversion process embodiments, electrical powerused in heating a relatively permeable formation may be supplied fromalternate energy sources. Alternate energy sources include, but are notlimited to, solar power, wind power, hydroelectric power, geothermalpower, biomass sources (i.e., agricultural and forestry by-products andenergy crops), and tidal power. Electric heaters used to heat aformation may use any available current, voltage (AC or DC), orfrequency that will not result in damage to the heater element. Becausethe heaters can be operated at a wide variety of voltages orfrequencies, transformers or other conversion equipment may not beneeded to allow for the use of electricity from alternate energy sourcesto power the electric heaters. This may significantly reduce equipmentcosts associated with using alternate energy sources, such as wind powerin which a significant cost is associated with equipment thatestablishes a relatively narrow current and/or voltage range.

[1191] Power generated from alternate energy sources may be generated ator proximate an area for treating a relatively permeable formation. Forexample, one or more solar panels and equipment for converting solarenergy to electricity may be placed at a location proximate a formation.A wind farm, which includes a plurality of wind turbines, may be placednear a formation that is to be, or is being, subjected to an in situconversion process. A power station that combusts or otherwise useslocal or imported biomass for electrical generation may be placed near aformation that is to be, or is being, subjected to an in situ conversionprocess. If suitable geothermal or hydroelectric sites are locatedsufficiently nearby, these resources may be used for power generation.Power for electric heaters may be generated at or proximate the locationof a formation, thus reducing costs associated with obtaining and/ortransporting electrical power. In certain embodiments, steam and/orother exhaust fluids from treating a formation may be used to power agenerator that is also primarily powered by wind turbines.

[1192] In an embodiment in which an alternate energy source such as windor solar power is used to power electric heaters, supplemental power maybe needed to complement the alternate energy source when the alternateenergy source does not provide sufficient power to supply the heaters.For example, with a wind power source, during times when there isinsufficient wind to power a wind turbine to provide power to anelectric heater, the additional power required may be obtained from linepower sources such as a fossil fuel plant or nuclear power plant. Inother embodiments, power from alternate energy sources may be used forsupplemental power in addition to power from line power sources toreduce costs associated with heating a formation.

[1193] Alternate energy sources such as wind or solar power may be usedto supplement or replace electrical grid power during peak energy costtimes. If excess electricity that is compatible with the electricitygrid is generated using alternate energy sources, the excess electricitymay be sold to the grid. If excess electricity is generated, and if theexcess energy is not easily compatible with an existing electricitygrid, the excess electricity may be used to create stored energy thatcan be recaptured at a later time. Methods of energy storage mayinclude, but are not limited to, converting water to oxygen andhydrogen, powering a flywheel for later recovery of the mechanicalenergy, pumping water into a higher reservoir for later use as ahydroelectric power source, and/or compression of air (as in undergroundcaverns or spent areas of the reservoir).

[1194] Use of wind, solar, hydroelectric, biomass, or other such energysources in an in situ conversion process essentially converts thealternate energy into liquid transportation fuels and other energycontaining hydrocarbons with a very high efficiency. Alternate energysource usage may allow reduced life cycle greenhouse gas emissions, asin many cases the alternate energy sources (other than biomass) wouldreplace an equivalent amount of power generated by fossil fuel. Even inthe case of biomass, the carbon dioxide emitted would not come fromfossil fuel, but would instead be recycled from the existing globalcarbon portfolio through photosynthesis. Unlike with fossil fuelcombustion, there would therefore be no net addition of carbon dioxideto the atmosphere. If carbon dioxide from the biomass was captured andsequestered underground or elsewhere, there may be a net removal ofcarbon from the environment.

[1195] Use of alternate energy sources may allow for formation heatingin areas where a power grid is lacking or where there otherwise isinsufficient coal, oil, or natural gas available for power generation.In embodiments of in situ conversion processes that use combustion(e.g., natural distributed combustors) for heating a portion of aformation, the use of alternate energy sources may allow start upwithout the need for construction of expensive power plants or gridconnections.

[1196] The use of alternate energy sources is not limited to supplyingelectricity for electric heaters. Alternate energy sources may also beused to supply power to surface facilities for processing fluidsproduced from a formation. Alternate energy sources may supply fuel forsurface burners or other gas combustors. For example, biomass mayproduce methane and/or other combustible hydrocarbons for reservoirheating.

[1197]FIG. 111 illustrates a schematic of an embodiment using wind togenerate electricity to heat a formation. Wind farm 6214 may include oneor more windmills. The windmills may be of any type of mechanism thatconverts wind to a usable mechanical form of motion. For example,windmill 6216 can be a design as shown in the embodiment of FIG. 111 orhave a design shown as an example in FIG. 112. In some embodiments, thewind farm may include advanced windmills as suggested by the NationalRenewable Energy Laboratory (Golden, Colo.). Wind farm 6214 may providepower to generator 6212. Generator 6212 may convert power from wind farm6214 into electrical power. In some embodiments, each windmill mayinclude a generator. Electrical power from generator 6212 may besupplied to formation 6210. The electrical power may be used information 6210 to power heaters, pumps, or any electrical equipment thatmay be used in treating formation 6210.

[1198]FIG. 113 illustrates a schematic of an embodiment for using solarpower to heat a formation. A heating fluid may be provided from storagetank 6220 to solar array 6224. The heating fluid may include any fluidthat has a relatively low viscosity with relatively good heat transferproperties (e.g., water, superheated steam, or molten ionic salts suchas molten carbonate). In certain embodiments, a low melting point ionicsalt may be used. Pump 6222 may be used to draw heating fluid fromstorage tank 6220 and provide the heating fluid to solar array 6224.Solar array 6224 may include any array designed to heat the heatingfluid to a relatively high temperature (e.g., above about 650° C.) usingsolar energy. For example, solar array 6224 may include a reflectivetrough with the heating fluid flowing through tubes within thereflective trough. The heating fluid may be provided to heater wells6230 through hot fluid conduit 6226. Each heater well 6230 may becoupled to a branch of hot fluid conduit 6226. A portion of the heatingfluid may be provided into each heater well 6230.

[1199] Each heater well 6230 may include two concentric conduits.Heating fluid may be provided into a heater well through an innerconduit. Heating fluid may then be removed from the heater well throughan outer conduit. Heat may be transferred from the heating fluid to atleast a portion of the formation within each heater well 6230 to provideheat to the formation. A portion of each heater well 6230 in anoverburden of the formation may be insulated such that no heat istransferred from the heating fluid to the overburden. Heating fluid fromeach heater well 6230 may flow into cold fluid conduit 6228, which mayreturn the heating fluid to storage tank 6220. Heating fluid may havecooled within the heater well to a temperature of about 480° C. Heatingfluid may be recirculated in a closed loop process as needed. Anadvantage of using the heating fluid to provide heat to the formationmay be that solar power is used directly to heat the formation withoutconverting the solar power to electricity.

[1200] Certain in situ conversion embodiments may include providing heatto a first portion of a relatively permeable formation from one or moreheat sources. Formation fluids may be produced from the first portion. Asecond portion of the formation may remain unpyrolyzed by maintainingtemperature in the second portion below a pyrolysis temperature ofhydrocarbons in the formation. In some embodiments, the second portionor significant sections of the second portion may remain unheated.

[1201] A second portion that remains unpyrolyzed may be adjacent to afirst portion of the formation that is subjected to pyrolysis. Thesecond portion may provide structural strength to the formation. Thesecond portion may be between the first portion and the third portion.Formation fluids may be produced from the third portion of theformation. A processed formation may have a pattern that resembles astriped or checkerboard pattern with alternating pyrolyzed portions andunpyrolyzed portions. In some in situ conversion embodiments, columns ofunpyrolyzed portions of formation may remain in a formation that hasundergone in situ conversion.

[1202] Unpyrolyzed portions of formation among pyrolyzed portions offormation may provide structural strength to the formation. Thestructural strength may inhibit subsidence of the formation. Inhibitingsubsidence may reduce or eliminate subsidence problems such as changingsurface levels and/or decreasing permeability and flow of fluids in theformation due to compaction of the formation.

[1203] Temperature (and average temperatures) within a heated relativelypermeable formation may vary depending on a number of factors. Thefactors may include, but are not limited to proximity to a heat source,thermal conductivity and thermal diffusivity of the formation, type ofreaction occurring, type of relatively permeable formation, and thepresence of water within the relatively permeable formation. Atemperature within the relatively permeable formation may be assessedusing a numerical simulation model. The numerical simulation model maycalculate a subsurface temperature distribution. In addition, thenumerical simulation model may assess various properties of a subsurfaceformation using the calculated temperature distribution.

[1204] Assessed properties of the subsurface formation may include, butare not limited to, thermal conductivity of the subsurface portion ofthe formation and permeability of the subsurface portion of theformation. The numerical simulation model may also assess variousproperties of fluid formed within a subsurface formation using thecalculated temperature distribution. Assessed properties of formed fluidmay include, but are not limited to, a cumulative volume of a fluidformed in the formation, fluid viscosity, fluid density, and acomposition of the fluid in the formation. The numerical simulationmodel may be used to assess the performance of commercial-scaleoperation of a small-scale field experiment. For example, a performanceof a commercial-scale development may be assessed based on, but is notlimited to, a total volume of product producible from a commercial-scaleoperation, amount of producible undesired products, and/or a time frameneeded before production becomes economical.

[1205] In some in situ conversion process embodiments, the in situconversion process increases a temperature or average temperature withina selected portion of a relatively permeable formation. A temperature oraverage temperature increase (ΔT) in a specified volume (V) of therelatively permeable formation may be assessed for a given heat inputrate (q) over time (t) by EQN. 21: $\begin{matrix}{{\Delta \quad T} = \frac{\sum\left( {q*t} \right)}{C_{V}*\rho_{B}*V}} & (21)\end{matrix}$

[1206] In EQN. 21, an average heat capacity of the formation (C_(v)) andan average bulk density of the formation (ρ_(B)) may be estimated ordetermined using one or more samples taken from the relatively permeableformation.

[1207] An in situ conversion process may include heating a specifiedvolume of relatively permeable formation to a pyrolysis temperature oraverage pyrolysis temperature. Heat input rate (q) during a time (t)required to heat the specified volume (V) to a desired temperatureincrease (ΔT) may be determined or assessed using EQN. 22:

Σq*t=ΔT*C _(V)*ρ_(B) *V  (22)

[1208] In EQN. 22, an average heat capacity of the formation (C_(v)) andan average bulk density of the formation (ρ_(B)) may be estimated ordetermined using one or more samples taken from the relatively permeableformation.

[1209] EQNS. 21 and 22 may be used to assess or estimate temperatures,average temperatures (e.g., over selected sections of the formation),heat input, etc. Such equations do not take into account other factors(such as heat losses), which would also have some effect on heating andtemperature assessments. However such factors can ordinarily beaddressed with correction factors.

[1210] In some in situ conversion process embodiments, a portion of arelatively permeable formation may be heated at a heating rate in arange from about 0.1° C./day to about 50° C./day. Alternatively, aportion of a relatively permeable formation may be heated at a heatingrate in a range of about 0.1° C./day to about 10° C./day. For example, amajority of hydrocarbons may be produced from a formation at a heatingrate within a range of about 0.1° C./day to about 10° C./day. Inaddition, a relatively permeable formation may be heated at a rate ofless than about 0.7° C./day through a significant portion of a pyrolysistemperature range. The pyrolysis temperature range may include a rangeof temperatures as described in above embodiments. For example, theheated portion may be heated at such a rate for a time greater than 50%of the time needed to span the temperature range, more than 75% of thetime needed to span the temperature range, or more than 90% of the timeneeded to span the temperature range.

[1211] A rate at which a relatively permeable formation is heated mayaffect the quantity and quality of the formation fluids produced fromthe relatively permeable formation. For example, heating at high heatingrates may allow for production of a large quantity of condensablehydrocarbons from a relatively permeable formation. The products of sucha process may be of a significantly lower quality than would be producedusing heating rates less than about 10° C./day. Heating at a rate oftemperature increase less than approximately 10° C./day may allowpyrolysis to occur within a pyrolysis temperature range in whichproduction of undesirable products and heavy hydrocarbons may bereduced. In addition, a rate of temperature increase of less than about3° C./day may further increase the quality of the produced condensablehydrocarbons by further reducing the production of undesirable productsand further reducing production of heavy hydrocarbons from a relativelypermeable formation.

[1212] In some in situ conversion process embodiments, controllingtemperature within a relatively permeable formation may involvecontrolling a heating rate within the formation. For example,controlling the heating rate such that the heating rate is less thanapproximately 3° C./day may provide better control of temperature withinthe relatively permeable formation.

[1213] An in situ process for hydrocarbons may include monitoring a rateof temperature increase at a production well. A temperature within aportion of a relatively permeable formation, however, may be measured atvarious locations within the portion of the formation. An in situprocess may include monitoring a temperature of the portion at amidpoint between two adjacent heat sources. The temperature may bemonitored over time to allow for calculation of rate of temperatureincrease. A rate of temperature increase may affect a composition offormation fluids produced from the formation. Energy input into aformation may be adjusted to change a heating rate of the formationbased on calculated rate of temperature increase in the formation topromote production of desired products.

[1214] In some embodiments, a power (Pwr) required to generate a heatingrate (h) in a selected volume (Y) of a relatively permeable formationmay be determined by EQN. 23:

Pwr=h*V*C _(V)*ρ_(B)  (23)

[1215] In EQN. 23, an average heat capacity of the relatively permeableformation is described as C_(V). The average heat capacity of therelatively permeable formation may be a relatively constant value.Average heat capacity may be estimated or determined using one or moresamples taken from a relatively permeable formation, or the average heatcapacity may be measured in situ using a thermal pulse test. Methods ofdetermining average heat capacity based on a thermal pulse test aredescribed by I. Berchenko, E. Detoumay, N. Chandler, J. Martino, and E.Kozak, “In-situ measurement of some thermoporoelastic parameters of agranite” in Poromechanics, A Tribute to Maurice A. Biot., pages 545-550,Rotterdam, 1998 (Balkema), which is incorporated by reference as iffully set forth herein.

[1216] An average bulk density of the relatively permeable formation isdescribed as ρ_(B). The average bulk density of the relatively permeableformation may be a relatively constant value. Average bulk density maybe estimated or determined using one or more samples taken from arelatively permeable formation. In certain embodiments, the product ofaverage heat capacity and average bulk density of the relativelypermeable formation may be a relatively constant value (such product canbe assessed in situ using a thermal pulse test).

[1217] A determined power may be used to determine heat provided from aheat source into the selected volume such that the selected volume maybe heated at a heating rate, h. For example, a heating rate may be lessthan about 3° C./day, and even less than about 2° C./day. A heating ratewithin a range of heating rates may be maintained within the selectedvolume. It is to be understood that in this context “power” is used todescribe energy input per time. The form of such energy input may vary(e.g., energy may be provided from electrical resistance heaters,combustion heaters, etc.).

[1218] The heating rate may be selected based on a number of factorsincluding, but not limited to, the maximum temperature possible at thewell, a predetermined quality of formation fluids that may be producedfrom the formation, and/or spacing between heat sources. A quality ofhydrocarbon fluids may be defined by an API gravity of condensablehydrocarbons, by olefin content, by the nitrogen, sulfur and/or oxygencontent, etc. In an in situ conversion process embodiment, heat may beprovided to at least a portion of a relatively permeable formation toproduce formation fluids having an API gravity of greater than about20°. The API gravity may vary, however, depending on a number of factorsincluding the heating rate and a pressure within the portion of theformation and the time relative to initiation of the heat sources whenthe formation fluid is produced.

[1219] Subsurface pressure in a relatively permeable formation maycorrespond to the fluid pressure generated within the formation. Heatinghydrocarbons within a relatively permeable formation may generate fluidsby pyrolysis. The generated fluids may be vaporized within theformation. Vaporization and pyrolysis reactions may increase thepressure within the formation. Fluids that contribute to the increase inpressure may include, but are not limited to, fluids produced duringpyrolysis and water vaporized during heating. As temperatures within aselected section of a heated portion of the formation increase, apressure within the selected section may increase as a result ofincreased fluid generation and vaporization of water. Controlling a rateof fluid removal from the formation may allow for control of pressure inthe formation.

[1220] In some embodiments, pressure within a selected section of aheated portion of a relatively permeable formation may vary depending onfactors such as depth, distance from a heat source, a richness of thehydrocarbons within the relatively permeable formation, and/or adistance from a producer well. Pressure within a formation may bedetermined at a number of different locations (e.g., near or atproduction wells, near or at heat sources, or at monitor wells).

[1221] Heating of a relatively permeable formation to a pyrolysistemperature range may occur before substantial permeability has beengenerated within the relatively permeable formation. An initial lack ofpermeability may inhibit the transport of generated fluids from apyrolysis zone within the formation to a production well. As heat isinitially transferred from a heat source to a relatively permeableformation, a fluid pressure within the relatively permeable formationmay increase proximate a heat source. Such an increase in fluid pressuremay be caused by generation of fluids during pyrolysis of at least somehydrocarbons in the formation. The increased fluid pressure may bereleased, monitored, altered, and/or controlled through the heat source.For example, the heat source may include a valve that allows for removalof some fluid from the formation. In some heat source embodiments, theheat source may include an open wellbore configuration that inhibitspressure damage to the heat source.

[1222] In some in situ conversion process embodiments, pressuregenerated by expansion of pyrolysis fluids or other fluids generated inthe formation may be allowed to increase although an open path to theproduction well or any other pressure sink may not yet exist in theformation. The fluid pressure may be allowed to increase towards alithostatic pressure. Fractures in the relatively permeable formationmay form when the fluid approaches the lithostatic pressure. Forexample, fractures may form from a heat source to a production well. Thegeneration of fractures within the heated portion may relieve some ofthe pressure within the portion.

[1223] When permeability or flow channels to production wells areestablished, pressure within the formation may be controlled bycontrolling production rate from the production wells. In someembodiments, a back pressure may be maintained at production wells or atselected production wells to maintain a selected pressure within theheated portion.

[1224] In an embodiment, a method for treating a relatively permeableformation in situ may include adding hydrogen to a selected section ofthe formation when the selected section is at or undergoing certainconditions. For example, the hydrogen may be added through a heater wellor production well located in or proximate the selected section. Sincehydrogen is sometimes in relatively short supply (or relativelyexpensive to make or procure), hydrogen may be added when conditions inthe formation optimize the use of the added hydrogen. For example,hydrogen produced in a section of a formation undergoing synthesis gasgeneration may be added to a section of the formation undergoingpyrolysis. The added hydrogen in the pyrolysis section of the formationmay promote formation of aliphatic compounds and inhibit formation ofolefinic compounds that reduce the quality of hydrocarbon fluidsproduced from formation.

[1225] In some embodiments, hydrogen may be added to the selectedsection after an average temperature of the formation is at a pyrolysistemperature (e.g., when the selected section is at least about 270° C.).In some embodiments, hydrogen may be added to the selected section afterthe average temperature is at least about 290° C., 320° C., 375° C., or400° C. Hydrogen may be added to the selected section before an averagetemperature of the formation is about 400° C. In some embodiments,hydrogen may be added to the selected section before the averagetemperature is about 300° C. or about 325° C.

[1226] The average temperature of the formation may be controlled byselectively adding hydrogen to the selected section of the formation.Hydrogen added to the formation may react in exothermic reactions. Theexothermic reactions may heat the formation and reduce the amount ofenergy that needs to be supplied from heat sources to the formation. Insome embodiments, an amount of hydrogen may be added to the selectedsection of the formation such that an average temperature of theformation does not exceed about 400° C.

[1227] A valve may maintain, alter, and/or control a pressure within aheated portion of a relatively permeable formation. For example, a heatsource disposed within a relatively permeable formation may be coupledto a valve. The valve may release fluid from the formation through theheat source. In addition, a pressure valve may be coupled to aproduction well within the relatively permeable formation. In someembodiments, fluids released by the valves may be collected andtransported to a surface unit for further processing and/or treatment.

[1228] An in situ conversion process for hydrocarbons may includeproviding heat to a portion of a relatively permeable formation andcontrolling a temperature, rate of temperature increase, and/or pressurewithin the heated portion. A temperature and/or a rate of temperatureincrease of the heated portion may be controlled by altering the energysupplied to heat sources in the formation.

[1229] Formation fluid properties may vary depending on a location of aproduction well in the formation. For example, a location of aproduction well with respect to a location of a heat source in theformation may affect the composition of formation fluid produced fromthe formation. Distance between a production well and a heat source inthe formation may be varied to alter the composition of formation fluidproducible from the formation. Having a short distance between aproduction well and a heat source or heat sources may allow a hightemperature to be maintained at and adjacent to the production well.Having a high temperature at and adjacent to the production well mayallow a substantial portion of pyrolyzation fluids flowing to andthrough the production well to crack to non-condensable compounds. Insome in situ conversion process embodiments, location of productionwells relative to heat sources may be selected to allow for productionof formation fluid having a large non-condensable gas fraction. In somein situ conversion process embodiments, location of production wellsrelative to heat sources may be selected to increase a condensable gasfraction of the produced formation fluids. During operation of in situconversion process embodiments, energy input into heat sources adjacentto production wells may be controlled to allow for production of adesired ratio of non-condensable to condensable hydrocarbons.

[1230] A carbon number distribution of a produced formation fluid mayindicate a quality of the produced formation fluid. In general,condensable hydrocarbons with low carbon numbers are considered to bemore valuable than condensable hydrocarbons having higher carbonnumbers. Low carbon numbers may include, for example, carbon numbersless than about 25. High carbon numbers may include carbon numbersgreater than about 25. In an in situ conversion process embodiment, thein situ conversion process may include providing heat to a portion of aformation so that a majority of hydrocarbons produced from the formationhave carbon numbers of less than approximately 25.

[1231] An in situ conversion process may be operated so that carbonnumbers of the largest weight fraction of hydrocarbons produced from theformation are about 12, for a given time period. The time period may betotal time of operation, or a selected subset of operation (e.g., a day,week, month, year, etc.). Operating conditions of an in situ conversionprocess may be adjusted to shift the carbon number of the largest weightfraction of hydrocarbons produced from the formation. For example,increasing pressure in a formation may shift the carbon number of thelargest weight fraction of hydrocarbons produced from the formation to asmaller carbon number. Shifting the carbon number of the largest weightfraction of hydrocarbons produced from the formation may also beexpressed as shifting the mean carbon number of the carbon numberdistribution.

[1232] In some in situ conversion process embodiments, hydrocarbonsproduced from the formation may have a mean carbon number less thanabout 25. In some in situ conversion process embodiments, less thanabout 15 weight % of the hydrocarbons in the condensable hydrocarbonshave carbon numbers greater than approximately 25. In some embodiments,less than about 5 weight % of hydrocarbons in the condensablehydrocarbons have carbon numbers greater than about 25, and/or less thanabout 2 weight % of hydrocarbons in the condensable hydrocarbons havecarbon numbers greater than about 25.

[1233] In an in situ conversion process embodiment, the in situconversion process may include providing heat to at least a portion of arelatively permeable formation at a rate sufficient to alter and/orcontrol production of olefins. The in situ conversion process mayinclude heating the portion at a rate to produce formation fluids havingan olefin content of less than about 10 weight % of condensablehydrocarbons of the formation fluids. Reducing olefin production mayreduce coating of pipe surfaces by the olefins, thereby reducingdifficulty associated with transporting hydrocarbons through the piping.Reducing olefin production may inhibit polymerization of hydrocarbonsduring pyrolysis, thereby enhancing the quality of produced fluids(e.g., by lowering the mean carbon number of the carbon numberdistribution for fluids produced from the formation, increasing APIgravity, etc.).

[1234] In some in situ conversion process embodiments, however, theportion may be heated at a rate to allow for production of olefins fromformation fluid in sufficient quantities to allow for economic recoveryof the olefins. Olefins in produced formation fluid may be separatedfrom other hydrocarbons. Operating conditions (i.e., temperature andpressure) within the formation may be selected to control thecomposition of olefins produced along with other formation fluid. Forexample, operating conditions of an in situ conversion process may beselected to produce a carbon number distribution with a mean carbonnumber of about 9. Only a small weight fraction of the olefins producedmay have carbon numbers greater than 9. The small weight fraction maynot significantly affect the quality (e.g., API gravity) of the producedfluid from the formation. The fluid may remain easy to process even withenough olefins present to make separation of olefins economicallyviable.

[1235] In some in situ conversion process embodiments, a portion of theformation may be heated at a rate to selectively increase the content ofphenol and substituted phenols of condensable hydrocarbons in theproduced fluids. For example, phenol and/or substituted phenols may beseparated from condensable hydrocarbons. The separated compounds may beused to produce additional products. The resource may, in someembodiments, be selected to enhance production of phenol and/orsubstituted phenols.

[1236] Hydrocarbons in produced fluids may include a mixture of a numberof different hydrocarbon components. Hydrocarbons in formation fluidproduced from a formation may have a hydrogen to carbon atomic ratiothat is at least approximately 1.7 or above. For example, the hydrogento carbon atomic ratio of a produced fluid may be approximately 1.8,approximately 1.9, or greater. The ratio may be below two because of thepresence of aromatic compounds and/or olefins. Some of the hydrocarboncomponents are condensable and some are not. The fraction ofnon-condensable hydrocarbons within the produced fluid may be alteredand/or controlled by altering, controlling, and/or maintaining a hightemperature and/or high pressure during pyrolysis within the formation.Surface facilities may separate hydrocarbon fluids from non-hydrocarbonfluids. Surface facilities may also separate condensable hydrocarbonsfrom non-condensable hydrocarbons.

[1237] In some embodiments, the non-condensable hydrocarbons may includehydrocarbons having carbon numbers less than or equal to 5. Producedformation fluid may also include non-hydrocarbon, non-condensable fluidssuch as, but not limited to, H₂, CO₂, ammonia, H₂S, N₂ and/or CO. Incertain embodiments, non-condensable hydrocarbons of a fluid producedfrom a portion of a relatively permeable formation may have a weightratio of hydrocarbons having carbon numbers from 2 through 4 (“C₂₋₄hydrocarbons”) to methane of greater than about 0.3, greater than about0.75, or greater than about 1 in some circumstances. Hydrocarbonresource characteristics may influence the ratio of C₂₋₄ hydrocarbons tomethane. For example, a ratio of C₂₋₄ hydrocarbons to methane for aheavy hydrocarbon formation may be about 1. Operating conditions (e.g.,temperature and pressure) may be adjusted to influence a ratio of C₂₋₄hydrocarbons to methane. For example, producing hydrocarbons from arelatively hot formation at a relatively high formation may producesignificant amount of methane, which may result in a significantly lowervalue for the ratio of C₂₋₄ hydrocarbons to methane as compared to fluidproduced from the same formation at milder temperature and pressureconditions.

[1238] An in situ conversion process may be able to produce a highweight ratio of C₂₋₄ hydrocarbons to methane as compared to ratiosproducible using other processes such as fire floods or steam floods.High weight ratios of C₂₋₄ hydrocarbons to methane may indicate thepresence of significant amounts of hydrocarbons with 2, 3, and/or 4carbons (e.g., ethane, ethene, propane, propene, butane, and butene).C₂₋₄ hydrocarbons may have significant value. The value of C₃ and C₄hydrocarbons may be many times (e.g., 2, 3, or greater) than the valueof methane. Production of hydrocarbon fluids having high C₂₋₄hydrocarbons to methane weight ratios may be due to conditions appliedto the formation during pyrolysis (e.g., controlled heating and/orpressure used in reducing environments or non-oxidizing environments).The conditions may allow for long chain hydrocarbons to be reduced tosmall (and in many cases more saturated) chain hydrocarbons with only aportion of the long chain hydrocarbons being reduced to methane orcarbon dioxide.

[1239] Methane and at least a portion of ethane may be separated fromnon-condensable hydrocarbons in produced fluid. The methane and ethanemay be utilized as natural gas. A portion of propane and butane may beseparated from non-condensable hydrocarbons of the produced fluid. Inaddition, the separated propane and butane may be utilized as fuels oras feedstocks for producing other hydrocarbons. Ethane, propane andbutane produced from the formation may be used to generate olefins. Aportion of the produced fluid having carbon numbers less than 4 may bereformed to produce additional H₂ and/or methane. In some in situconversion process embodiments, the reformation may be performed in theformation. In addition, ethane, propane, and butane may be separatedfrom the non-condensable hydrocarbons.

[1240] Formation fluid produced from a formation during a pyrolysisstage of an in situ conversion process may have a H₂ content of greaterthan about 5 weight %, greater than about 10 weight %, or even greaterthan about 15 weight %. The H₂ may be used for a variety of purposes.The purposes may include, but are not limited to, as a fuel for a fuelcell, to hydrogenate hydrocarbon fluids in situ, and/or to hydrogenatehydrocarbon fluids ex situ.

[1241] Formation fluid produced from a formation may include somehydrogen-sulfide. The hydrogen sulfide may be a non-condensable,non-hydrocarbon component of the formation fluid. The hydrogen sulfidemay be separated from other compounds. The separated hydrogen sulfidemay be used to produce, for example, sulfuric acid, fertilizer, and/orelemental sulfur.

[1242] Formation fluid produced from a formation during in situconversion may include carbon dioxide. Carbon dioxide produced from theformation may be used for a variety of purposes. The purposes mayinclude, but are not limited to, drive fluid for enhanced oil recovery,drive fluid for coal bed methane production, as a feedstock forproduction of urea, and/or a component of a synthesis gas fluidgenerating fluid. In some embodiments, a portion of carbon dioxideproduced during an in situ conversion process may be sequestered in aspent portion of the formation being processed.

[1243] Formation fluid produced from a formation during in situconversion may include carbon monoxide. Carbon monoxide produced fromthe formation may be used, for example, as a feedstock for a fuel cell,as a feedstock for a Fischer-Tropsch process, as a feedstock forproduction of methanol, and/or as a feedstock for production of methane.

[1244] Condensable hydrocarbons of formation fluids produced from aformation may be separated from the formation fluids. Formation fluidsmay be separated into a non-condensable portion (hydrocarbon andnon-hydrocarbon) and a condensable portion (hydrocarbon andnon-hydrocarbon). The condensable portion may include condensablehydrocarbons and compounds found in an aqueous phase. The aqueous phasemay be separated from the condensable component.

[1245] An aqueous phase may include ammonia. The ammonia content of thetotal produced fluids may be greater than about 0.1 weight % of thefluid, greater than about 0.5 weight % of the fluid, and, in someembodiments, up to about 10 weight % of the produced fluids. The ammoniamay be used to produce, for example, urea.

[1246] In some in situ conversion process embodiments, condensablehydrocarbons of a fluid produced from a relatively permeable formationmay include olefins. For example, an olefin content of the condensablehydrocarbons may be in a range from about 0.1 weight % to about 15weight %. Alternatively, an olefin content of the condensablehydrocarbons may be within a range from about 0.1 weight % to about 5weight %. An olefin content of the condensable hydrocarbons may also bewithin a range from about 0.1 weight % to about 2.5 weight %. An olefincontent of the condensable hydrocarbons may be altered and/or controlledby controlling a pressure and/or a temperature within the formation. Forexample, olefin content of the condensable hydrocarbons may be reducedby selectively increasing pressure within the formation, by selectivelydecreasing temperature within the formation, by selectively reducingheating rates within the formation, and/or by selectively increasinghydrogen partial pressures in the formation. In some in situ conversionprocess embodiments, a reduced olefin content of the condensablehydrocarbons may be desired. For example, if a portion of the producedfluids is used to produce motor fuels, a reduced olefin content may bedesired.

[1247] In some in situ conversion process embodiments, a higher olefincontent may be desired. For example, if a portion of the condensablehydrocarbons may be sold, a higher olefin content may be selected due toa high economic value of olefin products. In some embodiments, olefinsmay be separated from the produced fluids and then sold and/or used as afeedstock for the production of other compounds.

[1248] Non-condensable hydrocarbons of a produced fluid may includeolefins. An ethene/ethane molar ratio may be used as an estimate ofolefin content of non-condensable hydrocarbons. In certain in situconversion process embodiments, the ethene/ethane molar ratio may rangefrom about 0.001 to about 0.15.

[1249] Fluid produced from a relatively permeable formation may includearomatic compounds. For example, the condensable hydrocarbons mayinclude an amount of aromatic compounds greater than about 20 weight %or about 25 weight % of the condensable hydrocarbons. Alternatively, thecondensable hydrocarbons may include an amount of aromatic compoundsgreater than about 30 weight % of the condensable hydrocarbons. Thecondensable hydrocarbons may also include relatively low amounts ofcompounds with more than two rings in them (e.g., tri-aromatics orabove). For example, the condensable hydrocarbons may include less thanabout 1 weight % or less than about 2 weight % of tri-aromatics or abovein the condensable hydrocarbons. Alternatively, the condensablehydrocarbons may include less than about 5 weight % of tri-aromatics orabove in the condensable hydrocarbons.

[1250] Fluid produced from a relatively permeable formation may includea small amount of asphaltenes (i.e., large multi-ring aromatics that maybe substantially soluble in hydrocarbons) as compared to fluid producedfrom a formation using other techniques such as fire floods and/or steamfloods. Temperature and pressure control within a selected portion mayinhibit the production of asphaltenes using an in situ conversionprocess. Some asphaltenes may be entrained in formation fluid producedfrom the formation. Asphaltenes may make up less than about 0.3 weight %of the condensable hydrocarbons produced using an in situ conversionprocess. In some in situ conversion process embodiments, asphaltenes maybe less than 0.1 weight %, 0.05 weight %, or 0.01 weight %. In some insitu conversion process embodiments, the in situ conversion process mayresult in no, or substantially no, asphaltene production, especially ifinitial production from the formation is inhibited or if initialproduction is ignored until the formation produces hydrocarbons of aminimum quality.

[1251] Condensable hydrocarbons of a produced fluid may includerelatively large amounts of cycloalkanes. Linear chain molecules mayform ring compounds (e.g., hexane may form cyclohexane) in theformation. In addition, some aromatic compounds may be hydrogenated inthe formation to produce cycloalkanes (e.g., benzene may be hydrogenatedto form cyclohexane). The condensable hydrocarbons may include acycloalkane component of from about 0 weight % to about 30 weight %. Insome in situ conversion process embodiments, the condensablehydrocarbons may include a cycloalkane component from about 1% to about20%, or from about 5% to about 20%.

[1252] In certain in situ conversion process embodiments, thecondensable hydrocarbons of a fluid produced from a formation mayinclude compounds containing nitrogen. For example, less than about 1weight % (when calculated on an elemental basis) of the condensablehydrocarbons may be nitrogen (e.g., typically the nitrogen may be innitrogen containing compounds such as pyridines, amines, amides,carbazoles, etc.). The amount of nitrogen containing compounds maydepend on the amount of nitrogen in the initial hydrocarbon materialpresent in the formation.

[1253] Some of the nitrogen in the initial hydrocarbon material presentmay be produced as ammonia. Produced ammonia may be separated fromhydrocarbons. The ammonia may be separated, along with water, fromformation fluid produced from the formation. Formation fluid producedfrom the formation may include about 0.05 weight % or more of ammonia.

[1254] In certain in situ conversion process embodiments, thecondensable hydrocarbons of a fluid produced from a formation mayinclude compounds containing oxygen. For example, in certain embodiments(e.g., for heavy hydrocarbons), less than about 1 weight % (whencalculated on an elemental basis) of the condensable hydrocarbons may beoxygen containing compounds (e.g., typically the oxygen may be in oxygencontaining compounds such as phenol, substituted phenols, ketones,etc.). In some instances, certain compounds containing oxygen (e.g.,phenols) may be valuable and, as such, may be economically separatedfrom the produced fluid. Other types of formations (e.g., tar sandsformations or other mature hydrocarbon formations) may containinsignificant or no oxygen containing compounds in the initialhydrocarbon material. Such formations may not produce any or onlyinsignificant amounts of oxygenated compounds. Some of the oxygen in theinitial hydrocarbon material may be produced as carbon dioxide.

[1255] In some in situ conversion process embodiments, condensablehydrocarbons of the fluid produced from a formation may includecompounds containing sulfur. For example, less than about 1 weight %(when calculated on an elemental basis) of the condensable hydrocarbonsmay be sulfur containing compounds. Typical sulfur containing compoundsmay include compounds such as thiophenes, mercaptans, etc. The amount ofsulfur containing compounds may depend on the amount of sulfur in theinitial hydrocarbon material present in the formation. Some of thesulfur in the initial hydrocarbon material present may be produced ashydrogen sulfide.

[1256] In some in situ conversion process embodiments, formation fluidproduced from the formation may include molecular hydrogen (H₂).Hydrogen may be from about 0.1 volume % to about 80 volume % of anon-condensable component of formation fluid produced from theformation. In some in situ conversion process embodiments, H₂ may beabout 5 volume % to about 70 volume % of the non-condensable componentof formation fluid produced from the formation. The amount of hydrogenin the formation fluid may be strongly dependent on the temperature ofthe formation. A high formation temperature may result in the productionof significant amounts of hydrogen. A high temperature may also resultin the formation of a significant amount of coke within the formation.

[1257] In some in situ conversion process embodiments, a large portionof the total organic carbon content of a formation may be converted intohydrocarbon fluids. In some embodiments, up to about 20 weight % of thetotal organic carbon content of hydrocarbons in the portion may betransformed into hydrocarbon fluids. In some in situ conversion processembodiments, the weight percentage of total organic carbon content ofhydrocarbons in the portion removed during the in situ process may besignificantly increased if synthesis gas is generated within theportion.

[1258] In certain embodiments, heating of the selected section of theformation may be controlled to pyrolyze at least about 20 weight % (orin some embodiments about 25 weight %) of the hydrocarbons within theselected section of the formation. Conversion of selected portions ofhydrocarbon layers within a formation may be avoided to inhibitsubsidence of the formation.

[1259] Heating at least a portion of a formation may cause some of thehydrocarbons within the portion to pyrolyze. Pyrolyzation may generatehydrocarbon fragments. The hydrocarbon fragments may be reactive and mayreact with other compounds in the formation and/or with otherhydrocarbon fragments produced by pyrolysis. Reaction of the hydrocarbonfragments with other compounds and/or with each other, however, mayreduce production of a selected product. A reducing agent in, orprovided to, the portion of the formation during heating may increaseproduction of the selected product. The reducing agent may be, but isnot limited to, H₂, methane, and/or other non-condensable hydrocarbonfluids.

[1260] In an in situ conversion process embodiment, molecular hydrogenmay be provided to the formation to create a reducing environment.Hydrogenation reactions between the molecular hydrogen and some of thehydrocarbons within a portion of the formation may generate heat. Theheat may heat the portion of the formation. Molecular hydrogen may alsobe generated within the portion of the formation. The generated H₂ mayhydrogenate hydrocarbon fluids within a portion of a formation. Thehydrogenation may generate heat that transfers to the formation tomaintain a desired temperature within the formation.

[1261] H₂ may be produced from a first portion of a relatively permeableformation. The H₂ may be separated from formation fluid produced fromthe first portion. The H₂ from the first portion, along with otherreducing or substantially inert fluid (e.g., methane, ethane, and/ornitrogen), may be provided to a second portion of the formation tocreate a reducing environment within the second portion. The secondportion of the formation may be heated by heat sources. Power input intothe heat sources may be reduced after introduction of H₂ due to heatingof the formation by hydrogenation reactions within the formation. H₂ maybe introduced into the formation continuously or batchwise.

[1262] Hydrogen introduced into the second portion of the formation mayreduce (e.g., at least partially saturate) some pyrolyzation fluid beingproduced or present in the second section. Reducing the pyrolyzationfluid may decrease a concentration of olefins in the pyrolyzationfluids. Reducing the pyrolysis products may improve the product qualityof the hydrocarbon fluids.

[1263] An in situ conversion process may generate significant amounts ofH₂ and hydrocarbon fluids within the formation. Generation of hydrogenwithin the formation, and pressure within the formation sufficient toforce hydrogen into a liquid phase within the formation, may produce areducing environment within the formation without the need to introducea reducing fluid (e.g., H₂ and/or non-condensable saturatedhydrocarbons) into the formation. A hydrogen component of formationfluid produced from the formation may be separated and used for desiredpurposes. The desired purposes may include, but are not limited to, fuelfor fuel cells, fuel for combustors, and/or a feed stream for surfacehydrogenation units.

[1264] In an in situ conversion process embodiment, heating theformation may result in an increase in the thermal conductivity of aselected section of the heated portion. For example, porosity andpermeability within a selected section of the portion may increasesubstantially during heating such that heat may be transferred throughthe formation not only by conduction, but also by convection and/or byradiation from a heat source. Such radiant and convective transfer ofheat may increase an apparent thermal conductivity of the selectedsection and, consequently, the thermal diffusivity. The large apparentthermal diffusivity may make heating at least a portion of a relativelypermeable formation from heat sources feasible. For example, acombination of conductive, radiant, and/or convective heating mayaccelerate heating. Such accelerated heating may significantly decreasea time required for producing hydrocarbons and may significantlyincrease the economic feasibility of commercialization of the in situconversion process.

[1265] Thermal conductivity and thermal diffusivity within a relativelypermeable formation may vary depending on, for example, a density of therelatively permeable formation, a heat capacity of the formation, and athermal conductivity of the formation. As pyrolysis occurs within aselected section, a portion of hydrocarbon containing mass may beremoved from the selected section. The removal of mass may include, butis not limited to, removal of water and a transformation of hydrocarbonsto formation fluids. A lower thermal conductivity may be expected aswater is removed from a hydrocarbon formation. Reduction of thermalconductivity may be a function of depth of hydrocarbons in theformation. Lithostatic pressure may increase with depth. Deep in aformation, lithostatic pressure may close certain types of openings(e.g., cleats and/or fractures) in the formation. The closure of theformation openings may result in a decreased or minimal effect of massremoval from the formation on thermal conductivity and thermaldiffusivity.

[1266] In some in situ conversion process embodiments, the in situconversion process may generate molecular hydrogen during the pyrolysisprocess. In addition, pyrolysis tends to increase the porosity/voidspaces in the formation. Void spaces in the formation may containhydrogen gas generated by the pyrolysis process. Hydrogen gas may haveabout six times the thermal conductivity of nitrogen or air. Thepresence of hydrogen in void spaces may raise the thermal conductivityof the formation and decrease the effect of mass removal from theformation on thermal conductivity.

[1267] In some in situ conversion process embodiments, superposition(e.g., overlapping influence) of heat from one or more heat sources mayresult in substantially uniform heating of a portion of a relativelypermeable formation. Since formations during heating will typically havea temperature gradient that is highest near heat sources and reduceswith increasing distance from the heat sources, “substantially uniform”heating means heating such that temperature in a majority of the sectiondoes not vary by more than 100° C. from an assessed average temperaturein the majority of the selected section (volume) being treated.

[1268] Removal of hydrocarbons from the formation during an in situconversion process may occur on a microscopic scale, as well as amacroscopic scale (e.g., through production wells). Hydrocarbons may beremoved from micropores within a portion of the formation due toheating. Micropores may be generally defined as pores having across-sectional dimension of less than about 1000 Å. Removal of solidhydrocarbons may result in a substantially uniform increase in porositywithin at least a selected section of the heated portion. Heating theportion of a relatively permeable formation may substantially uniformlyincrease a porosity of a selected section within the heated portion.“Substantially uniform porosity” means that the assessed (e.g.,calculated or estimated) porosity of any selected portion in theformation does not vary by more than about 25% from the assessed averageporosity of such selected portion.

[1269] Physical characteristics of a portion of a relatively permeableformation after pyrolysis may be similar to those of a porous bed. Thephysical characteristics of a formation subjected to an in situconversion process may significantly differ from physicalcharacteristics of a relatively permeable formation subjected toinjection of gases that burn hydrocarbons to heat the hydrocarbons andor to formations subjected to steam flood production. Gases injectedinto virgin or fractured formations may channel through the formation.The gases may not be uniformly distributed throughout the formation. Incontrast, a gas injected into a portion of a relatively permeableformation subjected to an in situ conversion process may readily andsubstantially uniformly contact the carbon and/or hydrocarbons remainingin the formation. Gases produced by heating the hydrocarbons may betransferred a significant distance within the heated portion of theformation with minimal pressure loss.

[1270] Transfer of gases in a formation over significant distances maybe particularly advantageous to reduce the number of production wellsneeded to produce formation fluid from the formation. A first portion ofa hydrocarbon formation may be subjected to an in situ conversionprocess. The volume of the formation subjected to in situ conversion maybe expanded by heating abutting portions of the relatively permeableformation. Formation fluid produced in the abutting portions of theformation may be produced from production wells in the first portion. Ifneeded, a few additional production wells may be installed in theabutting portions of formation, but such production wells may have largeseparation distances. The ability to transfer fluid in a formation overlong distances may be advantageous for treating a steeply dippingrelatively permeable formation. Production wells may be placed in anupper portion of the dipping hydrocarbon production. Heat sources may beinserted into the steeply dipping formation. The heat sources may followthe dip of the formation. The upper portion may be subjected to thermaltreatment by activating portions of the heat sources in the upperportion. Abutting portions of the steeply dipping formation may besubjected to thermal treatment after treatment in the upper portionincreases the permeability of the formation so that fluids in lowerportions may be produced from the upper portions.

[1271] Synthesis gas may be produced from a portion of a relativelypermeable formation. Synthesis gas may be produced from heavyhydrocarbon (tar sands, etc.) and other bitumen containing formations.The relatively permeable formation may be heated prior to synthesis gasgeneration to produce a substantially uniform, relatively highpermeability formation. In an in situ conversion process embodiment,synthesis gas production may be commenced after production of pyrolysisfluids has been exhausted or becomes uneconomical. Alternately,synthesis gas generation may be commenced before substantial exhaustionor uneconomical pyrolysis fluid production has been achieved ifproduction of synthesis gas will be more economically favorable.Formation temperatures will usually be higher than pyrolysistemperatures during synthesis gas generation. Raising the formationtemperature from pyrolysis temperatures to synthesis gas generationtemperatures allows further utilization of heat applied to the formationto pyrolyze the formation. While raising a temperature of a formationfrom pyrolysis temperatures to synthesis gas temperatures, methaneand/or H₂ may be produced from the formation.

[1272] Producing synthesis gas from a formation from which pyrolyzationfluids have been previously removed allows a synthesis gas to beproduced that includes mostly H₂, CO, water, and/or CO₂. Producedsynthesis gas, in certain embodiments, may have substantially nohydrocarbon component unless a separate source hydrocarbon stream isintroduced into the formation with or in addition to the synthesis gasproducing fluid. Producing synthesis gas from a substantially uniform,relatively high permeability formation that was formed by slowly heatinga formation through pyrolysis temperatures may allow for easyintroduction of a synthesis gas generating fluid into the formation, andmay allow the synthesis gas generating fluid to contact a relativelylarge portion of the formation. The synthesis gas generating fluid cando so because the permeability of the formation has been increasedduring pyrolysis and/or because the surface area per volume in theformation has increased during pyrolysis. The relatively large surfacearea (e.g., “contact area”) in the post-pyrolysis formation tends toallow synthesis gas generating reactions to be substantially atequilibrium conditions for C, H₂, CO, water, and CO₂. Reactions in whichmethane is formed may, however, not be at equilibrium because they arekinetically limited. The relatively high, substantially uniformformation permeability may allow production wells to be spaced fartherapart than production wells used during pyrolysis of the formation.

[1273] A temperature of at least a portion of a formation that is usedto generate synthesis gas may be raised to a synthesis gas generatingtemperature (e.g., between about 400° C. and about 1200° C.). In someembodiments, composition of produced synthesis gas may be affected byformation temperature, by the temperature of the formation adjacent tosynthesis gas production wells, and/or by residence time of thesynthesis gas components. A relatively low synthesis gas generationtemperature may produce a synthesis gas having a high H₂ to CO ratio,but the produced synthesis gas may also include a large portion of othergases such as water, CO₂, and methane. A relatively high formationtemperature may produce a synthesis gas having a H₂ to CO ratio thatapproaches 1, and the stream may include mostly and, in some cases, onlyH₂ and CO. If the synthesis gas generating fluid is substantially puresteam, then the H₂ to CO ratio may approach 1 at relatively hightemperatures. At a formation temperature of about 700° C., the formationmay produce a synthesis gas with a H₂ to CO ratio of about 2 at acertain pressure. The composition of the synthesis gas tends to dependon the nature of the synthesis gas generating fluid.

[1274] Synthesis gas generation is generally an endothermic process.Heat may be added to a portion of a formation during synthesis gasproduction to keep formation temperature at a desired synthesis gasgenerating temperature or above a minimum synthesis gas generatingtemperature. Heat may be added to the formation from heat sources, fromoxidation reactions within the portion, and/or from introducingsynthesis gas generating fluid into the formation at a highertemperature than the temperature of the formation.

[1275] An oxidant may be introduced into a portion of the formation withsynthesis gas generating fluid. The oxidant may exothermically reactwith carbon within the portion of the formation to heat the formation.Oxidation of carbon within a formation may allow a portion of aformation to be economically heated to relatively high synthesis gasgenerating temperatures. The oxidant may be introduced into theformation without synthesis gas generating fluid to heat the portion.Using an oxidant, or an oxidant and heat sources, to heat the portion ofthe formation may be significantly more favorable than heating theportion of the formation with only the heat sources. The oxidant may be,but is not limited to, air, oxygen, or oxygen enriched air. The oxidantmay react with carbon in the formation to produce CO₂ and/or CO. The useof air, or oxygen enriched air (i.e., air with an oxygen content greaterthan 21 volume %), to generate heat within the formation may cause asignificant portion of N₂ to be present in produced synthesis gas.Temperatures in the formation may be maintained below temperaturesneeded to generate oxides of nitrogen (NO_(x)), so that little or noNO_(x) compounds may be present in produced synthesis gas.

[1276] A mixture of steam and oxygen, steam and enriched air, or steamand air, may be continuously injected into a formation. If injection ofsteam and oxygen or steam and enriched air is used for synthesis gasproduction, the oxygen may be produced on site (or near to the site) byelectrolysis of water utilizing direct current output of a fuel cell. H₂produced by the electrolysis of water may be used as a fuel stream forthe fuel cell. O₂ produced by the electrolysis of water may also beinjected into the hot formation to raise a temperature of the formation.

[1277] Heat sources and/or production wells within a formation forpyrolyzing and producing pyrolysis fluids from the formation may beutilized for different purposes during synthesis gas production. A wellthat was used as a heat source or a production well during pyrolysis maybe used as an injection well to introduce synthesis gas producing fluidinto the formation. A well that was used as a heat source or aproduction well during pyrolysis may be used as a production well duringsynthesis gas generation. A well that was used as a heat source or aproduction well during pyrolysis may be used as a heat source to heatthe formation during synthesis gas generation. Some production wellsused during a pyrolysis phase may be shut in. Synthesis gas productionwells may be spaced further apart than pyrolysis production wellsbecause of the relatively high, substantially uniform permeability ofthe formation. Some production wells used during a pyrolysis phase maybe shut in or converted to other uses. Synthesis gas production wellsmay be heated to relatively high temperatures so that a portion of theformation adjacent to the production well is at a temperature that willproduce a desired synthesis gas composition. Comparatively, pyrolysisfluid production wells may not be heated at all, or may only be heatedto a temperature that will inhibit condensation of pyrolysis fluidwithin the production well.

[1278] Synthesis gas may be produced from a dipping formation from wellsused during pyrolysis of the formation. As shown in FIG. 8, synthesisgas production wells 206 may be located above and down dip frominjection well 202. Hot synthesis gas producing fluid may be introducedinto injection well 202. Hot synthesis gas fluid that moves down dip maygenerate synthesis gas that is produced through synthesis gas productionwells 206. Synthesis gas generating fluid that moves up dip may generatesynthesis gas in a portion of the formation that is at synthesis gasgenerating temperatures. A portion of the synthesis gas generating fluidand generated synthesis gas that moves up dip above the portion of theformation at synthesis gas generating temperatures may heat adjacentportions of the formation. The synthesis gas generating fluid that movesup dip may condense, heat adjacent portions of formation, and flowdownwards towards or into a portion of the formation at synthesis gasgenerating temperature. The synthesis gas generating fluid may thengenerate additional synthesis gas.

[1279] Synthesis gas generating fluid may be any fluid capable ofgenerating H₂ and CO within a heated portion of a formation. Synthesisgas generating fluid may include water, O₂, air, CO₂, hydrocarbonfluids, or combinations thereof. Water may be introduced into aformation as a liquid or as steam. Water may react with carbon in aformation to produce H₂, CO, and CO₂. CO₂ may react with hot carbon toform CO. Air and O₂ may be oxidants that react with carbon in aformation to generate heat and form CO₂, CO, and other compounds.Hydrocarbon fluids may react within a formation to form H₂, CO, CO₂,H₂O, coke, methane, and/or other light hydrocarbons. Introducing lowcarbon number hydrocarbons (i.e., compounds with carbon numbers lessthan 5) may produce additional H₂ within the formation. Adding highercarbon number hydrocarbons to the formation may increase an energycontent of generated synthesis gas by having a significant methane andother low carbon number compounds fraction within the synthesis gas.

[1280] Water provided as a synthesis gas generating fluid may be derivedfrom numerous different sources. Water may be produced during apyrolysis stage of treating a formation. The water may include someentrained hydrocarbon fluids. Such fluid may be used as synthesis gasgenerating fluid. Water that includes hydrocarbons may advantageouslygenerate additional H₂ when used as a synthesis gas generating fluid.Water produced from water pumps that inhibit water flow into a portionof formation being subjected to an in situ conversion process mayprovide water for synthesis gas generation.

[1281] Reactions involved in the formation of synthesis gas may include,but are not limited to:

C+H₂O⇄H₂+CO  (24)

C+2H₂O⇄2H₂+CO₂  (25)

C+CO₂⇄2CO  (26)

[1282] Thermodynamics also allows the following reactions to proceed:

2C+2H₂O⇄CH₄+CO₂  (27)

C+2H₂⇄CH₄  (28)

[1283] However, kinetics of the reactions are slow in certainembodiments, so that relatively low amounts of methane are formed atformation conditions from Reactions 27 and 28.

[1284] In the presence of oxygen, the following reaction may take placeto generate carbon dioxide and heat:

C+O₂⇄CO₂  (29)

[1285] Equilibrium gas phase compositions of hydrocarbons in contactwith steam may provide an indication of the compositions of componentsproduced in a formation during synthesis gas generation. Equilibriumcomposition data for H₂, carbon monoxide, and carbon dioxide may be usedto determine appropriate operating conditions (e.g., temperature) thatmay be used to produce a synthesis gas having a selected composition.Equilibrium conditions may be approached within a formation due to ahigh, substantially uniform permeability of the formation. Compositiondata obtained from synthesis gas production may in many in situconversion process embodiments, deviate by less than 10% fromequilibrium values.

[1286] In one synthesis gas production embodiment, a composition of theproduced synthesis gas can be changed by injecting additional componentsinto the formation along with steam. Carbon dioxide may be provided inthe synthesis gas generating fluid to inhibit production of carbondioxide from the formation during synthesis gas generation. The carbondioxide may shift the equilibrium of Reaction 25 to the left, thusreducing the amount of carbon dioxide generated from formation carbon.The carbon dioxide may also shift the equilibrium of Reaction 26 to theright to generate carbon monoxide. Carbon dioxide may be separated fromthe synthesis gas and may be re-injected into the formation with thesynthesis gas generating fluid. Addition of carbon dioxide in thesynthesis gas generating fluid may, however, reduce the production ofhydrogen.

[1287]FIG. 114 depicts a schematic diagram of use of water recoveredfrom pyrolysis fluid production to generate synthesis gas. Heat source801 with electric heater 803 produces pyrolysis fluid 807 from firstsection 805 of the formation. Produced pyrolysis fluid 807 may be sentto separator 809. Separator 809 may include a number of individualseparation units and processing units that produce aqueous stream 811,vapor stream 813, and hydrocarbon condensate stream 815. Aqueous stream811 from separator 809 may be combined with synthesis gas generatingfluid 818 to form synthesis gas generating fluid 821. Synthesis gasgenerating fluid 821 may be provided to injection well 817 andintroduced to second portion 819 of the formation. Synthesis gas 823 maybe produced from synthesis gas production well 825.

[1288]FIG. 115 depicts a schematic diagram of an embodiment of a systemfor synthesis gas production. Synthesis gas 830 may be produced fromformation 832 through production well 834. Gas separation unit 836 mayseparate a portion of carbon dioxide from synthesis gas 830 to produceCO₂ stream 838 and remaining synthesis gas stream 840. CO₂ stream 838may be mixed with synthesis gas producing fluid stream 842 that isintroduced into formation 832 through injection well 837. In somesynthesis gas process embodiments, CO₂ may be introduced into theformation separate from synthesis gas producing fluid. Introducing CO₂may inhibit conversion of carbon within the formation to CO₂ and/or mayincrease an amount of CO generated within the formation.

[1289] Synthesis gas generating fluid may be introduced into a formationin a variety of different ways. Steam may be injected into a heatedrelatively permeable formation at a lowermost portion of the heatedformation. Alternatively, in a steeply dipping formation, steam may beinjected up dip with synthesis gas production down dip. The injectedsteam may pass through the remaining relatively permeable formation to aproduction well. In addition, endothermic heat of reaction may beprovided to the formation with heat sources disposed along a path of theinjected steam. In alternate embodiments, steam may be injected at aplurality of locations along the relatively permeable formation toincrease penetration of the steam throughout the formation. A line drivepattern of locations may also be utilized. The line drive pattern mayinclude alternating rows of steam injection wells and synthesis gasproduction wells.

[1290] Synthesis gas reactions may be slow at relatively low pressuresand at temperatures below about 400° C. At relatively low pressures, andtemperatures between about 400° C. and about 700° C., Reaction 25 maypredominate so that synthesis gas composition is primarily hydrogen andcarbon dioxide. At relatively low pressures and temperatures greaterthan about 700° C., Reaction 24 may predominate so that synthesis gascomposition is primarily hydrogen and carbon monoxide.

[1291] Advantages of a lower temperature synthesis gas reaction mayinclude lower heat requirements, cheaper metallurgy, and lessendothermic reactions (especially when methane formation takes place).An advantage of a higher temperature synthesis gas reaction is thathydrogen and carbon monoxide may be used as feedstock for otherprocesses (e.g., Fischer-Tropsch processes).

[1292] A pressure of the relatively permeable formation may bemaintained at relatively high pressures during synthesis gas production.The pressure may range from atmospheric pressure to a pressure thatapproaches a lithostatic pressure of the formation. Higher formationpressures may allow generation of electricity by passing producedsynthesis gas through a turbine. Higher formation pressures may allowfor smaller collection conduits to transport produced synthesis gas andreduced downstream compression requirements on the surface.

[1293] In some synthesis gas process embodiments, synthesis gas may beproduced from a portion of a formation in a substantially continuousmanner. The portion may be heated to a desired synthesis gas generatingtemperature. A synthesis gas generating fluid may be introduced into theportion. Heat may be added to, or generated within, the portion of theformation during introduction of the synthesis gas generating fluid tothe portion. The added heat may compensate for the loss of heat due tothe endothermic synthesis gas reactions as well as heat losses to a toplayer (overburden), bottom layer (underburden), and unreactive materialin the portion.

[1294]FIG. 116 illustrates a schematic representation of an embodimentof a continuous synthesis gas production system. FIG. 116 includes aformation with heat injection wellbore 850 and heat injection wellbore852. The wellbores may be members of a larger pattern of wellboresplaced throughout a portion of the formation. The portion of theformation may be heated to synthesis gas generating temperatures byheating the formation with heat sources, by injecting an oxidizingfluid, or by a combination thereof. Oxidizing fluid 854 (e.g., air,enriched air, or oxygen) and synthesis gas generating fluid 856 (e.g.,water, or steam) may be injected into wellbore 850. In a synthesis gasprocess embodiment that uses oxygen and steam, the ratio of oxygen tosteam may range from approximately 1:2 to approximately 1:10, orapproximately 1:3 to approximately 1:7 (e.g., about 1:4).

[1295] In situ combustion of hydrocarbons may heat region 858 of theformation between wellbores 850 and 852. Injection of the oxidizingfluid may heat region 858 to a particular temperature range, forexample, between about 600° C. and about 700° C. The temperature mayvary, however, depending on a desired composition of the synthesis gas.An advantage of the continuous production method may be that atemperature gradient established across region 858 may be substantiallyuniform and substantially constant with time once the formationapproaches thermal equilibrium. Continuous production may also eliminatea need for use of valves to reverse injection directions on a frequentbasis. Further, continuous production may reduce temperatures near theinjection wells due to endothermic cooling from the synthesis gasreaction that occur in the same region as oxidative heating. Thesubstantially constant temperature gradient may allow for control ofsynthesis gas composition. Produced synthesis gas 860 may exitcontinuously from wellbore 852.

[1296] In a synthesis gas process embodiment, oxygen may be used insteadof air as oxidizing fluid 854 in continuous production. If air is used,nitrogen may need to be separated from the produced synthesis gas. Theuse of oxygen as oxidizing fluid 854 may increase a cost of productiondue to the cost of obtaining substantially pure oxygen. The cryogenicnitrogen by-product obtained from an air separation plant used toproduce the required oxygen may, however, be used in a heat exchanger tocondense hydrocarbons from a hot vapor stream produced during pyrolysisof hydrocarbons. The pure nitrogen may also be used for ammoniaproduction.

[1297] In some synthesis gas process embodiments, synthesis gas may beproduced in a batch manner from a portion of the formation. The portionof the formation may be heated, or heat may be generated within theportion, to raise a temperature of the portion to a high synthesis gasgenerating temperature. Synthesis gas generating fluid may then be addedto the portion until generation of synthesis gas reduces the temperatureof the formation below a temperature that produces a desired synthesisgas composition. Introduction of the synthesis gas generating fluid maythen be stopped. The cycle may be repeated by reheating the portion ofthe formation to the high synthesis gas generating temperature andadding synthesis gas generating fluid after obtaining the high synthesisgas generating temperature. Composition of generated synthesis gas maybe monitored to determine when addition of synthesis gas generatingfluid to the formation should be stopped.

[1298]FIG. 117 illustrates a schematic representation of an embodimentof a batch production of synthesis gas in a relatively permeableformation. Wellbore 870 and wellbore 872 may be located within a portionof the formation. The wellbores may be members of a larger pattern ofwellbores throughout the portion of the formation. Oxidizing fluid 874,such as air or oxygen, may be injected into wellbore 870. Oxidation ofhydrocarbons may heat region 876 of a formation between wellbores 870and 872. Injection of air or oxygen may continue until an averagetemperature of region 876 is at a desired temperature (e.g., betweenabout 900° C. and about 1000° C.). Higher or lower temperatures may alsobe developed. A temperature gradient may be formed in region 876 betweenwellbore 870 and wellbore 872. The highest temperature of the gradientmay be located proximate injection wellbore 870.

[1299] When a desired temperature has been reached, or when oxidizingfluid has been injected for a desired period of time, oxidizing fluidinjection may be lessened and/or ceased. Synthesis gas generating fluid877, such as steam or water, may be injected into injection wellbore 872to produce synthesis gas. A back pressure of the injected steam or waterin the injection wellbore may force the synthesis gas produced andun-reacted steam across region 876. A decrease in average temperature ofregion 876 caused by the endothermic synthesis gas reaction may bepartially offset by the temperature gradient in region 876 in adirection indicated by arrow 878. Product stream 880 may be producedthrough heat source wellbore 870. If the composition of the productdeviates from a desired composition, then steam injection may cease, andair or oxygen injection may be reinitiated.

[1300] Synthesis gas of a selected composition may be produced byblending synthesis gas produced from different portions of theformation. A first portion of a formation may be heated by one or moreheat sources to a first temperature sufficient to allow generation ofsynthesis gas having a H₂ to carbon monoxide ratio of less than theselected H₂ to carbon monoxide ratio (e.g., about 1:1 or 2:1). A firstsynthesis gas generating fluid may be provided to the first portion togenerate a first synthesis gas. The first synthesis gas may be producedfrom the formation. A second portion of the formation may be heated byone or more heat sources to a second temperature sufficient to allowgeneration of synthesis gas having a H₂ to carbon monoxide ratio ofgreater than the selected H₂ to carbon monoxide ratio (e.g., a ratio of3:1 or more). A second synthesis gas generating fluid may be provided tothe second portion to generate a second synthesis gas. The secondsynthesis gas may be produced from the formation. The first synthesisgas may be blended with the second synthesis gas to produce a blendsynthesis gas having a desired H₂ to carbon monoxide ratio.

[1301] The first temperature may be different than the secondtemperature. Alternatively, the first and second temperatures may beapproximately the same temperature. For example, a temperaturesufficient to allow generation of synthesis gas having differentcompositions may vary depending on compositions of the first and secondportions and/or prior pyrolysis of hydrocarbons within the first andsecond portions. The first synthesis gas generating fluid may havesubstantially the same composition as the second synthesis gasgenerating fluid. Alternatively, the first synthesis gas generatingfluid may have a different composition than the second synthesis gasgenerating fluid. Appropriate first and second synthesis gas generatingfluids may vary depending upon, for example, temperatures of the firstand second portions, compositions of the first and second portions, andprior pyrolysis of hydrocarbons within the first and second portions.

[1302] In addition, synthesis gas having a selected ratio of 12 tocarbon monoxide may be obtained by controlling the temperature of theformation. In one embodiment, the temperature of an entire portion orsection of the formation may be controlled to yield synthesis gas with aselected ratio. Alternatively, the temperature in or proximate asynthesis gas production well may be controlled to yield synthesis gaswith the selected ratio. Controlling temperature near a production wellmay be sufficient because synthesis gas reactions may be fast enough toallow reactants and products to approach equilibrium concentrations.

[1303] In a synthesis gas process, synthesis gas having a selected ratioof H₂ to carbon monoxide may be obtained by treating produced synthesisgas at the surface. First, the temperature of the formation may becontrolled to yield synthesis gas with a ratio different than a selectedratio. For example, the formation may be maintained at a relatively hightemperature to generate a synthesis gas with a relatively low H₂ tocarbon monoxide ratio (e.g., the ratio may approach 1 under certainconditions). Some or all of the produced synthesis gas may then beprovided to a shift reactor (shift process) at the surface. Carbonmonoxide reacts with water in the shift process to produce H₂ and carbondioxide. Therefore, the shift process increases the H₂ to carbonmonoxide ratio. The carbon dioxide may then be separated to obtain asynthesis gas having a selected H₂ to carbon monoxide ratio.

[1304] Produced synthesis gas 918 may be used for production of energy.In FIG. 118, treated gases 920 may be routed from treatment section 900to energy generation unit 902 for extraction of useful energy. In someembodiments, energy may be extracted from the combustible gases in thesynthesis gas by oxidizing the gases to produce heat and converting aportion of the heat into mechanical and/or electrical energy.Alternatively, energy generation unit 902 may include a fuel cell thatproduces electrical energy. In addition, energy generation unit 902 mayinclude, for example, a molten carbonate fuel cell or another type offuel cell, a turbine, a boiler firebox, or a downhole gas heater.Produced electrical energy 904 may be supplied to power grid 906. Aportion of produced electricity 908 may be used to supply energy toelectrical heating elements 910 that heat formation 912.

[1305] In one embodiment, energy generation unit 902 may be a boilerfirebox. A firebox may include a small refractory-lined chamber, builtwholly or partly in the wall of a kiln, for combustion of fuel. Air oroxygen 914 may be supplied to energy generation unit 902 to oxidize theproduced synthesis gas. Water 916 produced by oxidation of the synthesisgas may be recycled to the formation to produce additional synthesisgas.

[1306] A portion of synthesis gas produced from a formation may, in someembodiments, be used for fuel in downhole gas heaters. Downhole gasheaters (e.g., flameless combustors, downhole combustors, etc.) may beused to provide heat to a relatively permeable formation. In someembodiments, downhole gas heaters may heat portions of a formationsubstantially by conduction of heat through the formation. Providingheat from gas heaters may be primarily self-reliant and may reduce oreliminate a need for electric heaters. Because downhole gas heaters mayhave thermal efficiencies approaching 90%, the amount of carbon dioxidereleased to the environment by downhole gas heaters may be less than theamount of carbon dioxide released to the environment from a processusing fossil-fuel generated electricity to heat the relatively permeableformation.

[1307] Carbon dioxide may be produced during pyrolysis and/or duringsynthesis gas generation. Carbon dioxide may also be produced by energygeneration processes and/or combustion processes. Net release of carbondioxide to the atmosphere from an in situ conversion process forhydrocarbons may be reduced by utilizing the produced carbon dioxideand/or by storing carbon dioxide within the formation or within anotherformation. For example, a portion of carbon dioxide produced from theformation may be utilized as a flooding agent or as a feedstock forproducing chemicals.

[1308] In an in situ conversion process embodiment, an energy generationprocess may produce a reduced amount of emissions by sequestering carbondioxide produced during extraction of useful energy. For example,emissions from an energy generation process may be reduced by storingcarbon dioxide within a relatively permeable formation. In an in situconversion process embodiment, the amount of stored carbon dioxide maybe approximately equivalent to that in an exit stream from theformation.

[1309]FIG. 118 illustrates a reduced emission energy process. Carbondioxide 928 produced by energy generation unit 902 may be separated fromfluids exiting the energy generation unit. Carbon dioxide may beseparated from H₂ at high temperatures by using a hot palladium filmsupported on porous stainless steel or a ceramic substrate, or by usinghigh temperature and pressure swing adsorption. The carbon dioxide maybe sequestered in spent relatively permeable formation 922, injectedinto oil producing fields 924 for enhanced oil recovery by improvingmobility and production of oil in such fields, sequestered into a deeprelatively permeable formation 926 containing methane by adsorption andsubsequent desorption of methane, or re-injected 928 into a section ofthe formation through a synthesis gas production well to enhanceproduction of carbon monoxide. Carbon dioxide leaving the energygeneration unit may be sequestered in a dewatered coal bed methanereservoir. The water for synthesis gas generation may come fromdewatering a coal bed methane reservoir. Additional methane may beproduced by alternating carbon dioxide and nitrogen. An example of amethod for sequestering carbon dioxide is illustrated in U.S. Pat. No.5,566,756 to Chaback et al., which is incorporated by reference as iffully set forth herein. Additional energy may be utilized by removingheat from the carbon dioxide stream leaving the energy generation unit.

[1310] In an in situ conversion process embodiment, a hot spentformation may be cooled before being used to sequester carbon dioxide.The spent formation may be cooled by introducing water into theformation. The steam produced may be removed from the formation throughproduction wells. The generated steam may be used for any desiredprocess. For example, the steam may be provided to an adjacent portionof a formation to heat the adjacent portion or to generate synthesisgas.

[1311]FIG. 119 illustrates an in situ conversion process embodiment inwhich fluid produced from pyrolysis may be separated into a fuel cellfeed stream and fed into a fuel cell to produce electricity. Theembodiment may include relatively permeable formation 940 withproduction well 942 that produces pyrolysis fluid. Heater well 944 withelectric heater 946 may be a heat source that heats, or contributes toheating, the formation. Heater well 944 may also be a production wellused to produce pyrolysis fluid 948. Pyrolysis fluid from heater well944 may include H₂ and hydrocarbons with carbon numbers less than 5.Larger chain hydrocarbons may be reduced to hydrocarbons with carbonnumbers less than 5 due to the heat adjacent to heater well 944.Pyrolysis fluid 948 produced from heater well 944 may be fed to gasmembrane separation system 950 to separate H₂ and hydrocarbons withcarbon numbers less than 5. Fuel cell feed stream 952, which may besubstantially composed of H₂, may be fed into fuel cell 954. Air feedstream 956 may be fed into fuel cell 954. Nitrogen stream 958 may bevented from fuel cell 954. Electricity 960 produced from the fuel cellmay be routed to a power grid. Electricity 962 may also be used to powerelectric heaters 946 in heater wells 944. Carbon dioxide 965 produced infuel cell 954 may be injected into formation 940.

[1312] Hydrocarbons having carbon numbers of 4, 3, and 1 typically havefairly high market values. Separation and selling of these hydrocarbonsmay be desirable. Ethane (carbon number 2) may not be sufficientlyvaluable to separate and sell in some markets. Ethane may be sent aspart of a fuel stream to a fuel cell or ethane may be used as ahydrocarbon fluid component of a synthesis gas generating fluid. Ethanemay also be used as a feedstock to produce ethene. In some markets,there may be no market for any hydrocarbons having carbon numbers lessthan 5. In such a situation, all of the hydrocarbon gases producedduring pyrolysis may be sent to fuel cells, used as fuels, and/or beused as hydrocarbon fluid components of a synthesis gas generatingfluid.

[1313] Pyrolysis fluid 964, which may be substantially composed ofhydrocarbons with carbon numbers less than 5, may be injected into a hotformation 940. When the hydrocarbons contact the formation, hydrocarbonsmay crack within the formation to produce methane, H₂, coke, and olefinssuch as ethene and propylene. In one embodiment, the production ofolefins may be increased by heating the temperature of the formation tothe upper end of the pyrolysis temperature range and by injectinghydrocarbon fluid at a relatively high rate. Residence time of thehydrocarbons in the formation may be reduced and dehydrogenatedhydrocarbons may form olefins rather than cracking to form H₂ and coke.Olefin production may also be increased by reducing formation pressure.

[1314] In some in situ conversion process embodiments, a hot formationthat was subjected to pyrolysis and/or synthesis gas generation may beused to produce olefins. Hot formation 940 may be significantly lessefficient at producing olefins than a reactor designed to produceolefins. However, a hot formation may have a several orders of magnitudemore surface area and volume than a reactor designed to produce olefins.The reduction in efficiency of a hot formation may be more than offsetby the increased size of the hot formation. A feed stream for olefinproduction in a hot formation may be produced adjacent to the hotformation from a portion of a formation undergoing pyrolysis. Theavailability of a feed stream may also offset efficiency of a hotformation for producing olefins as compared to generating olefins in areactor designed to produced olefins.

[1315] In some in situ conversion process embodiments, H₂ and/ornon-condensable hydrocarbons may be used as a fuel, or as a fuelcomponent, for surface burners or combustors. The combustors may be heatsources used to heat a relatively permeable formation. In some heatsource embodiments, the combustors may be flameless distributedcombustors. In some heat source embodiments, the combustors may benatural distributed combustors and the fuel may be provided to thenatural distributed combustor to supplement the fuel available fromhydrocarbon material in the formation.

[1316] Heater well 944 may heat a portion of a formation to a synthesisgas generating temperature range. Pyrolysis fluid 964, or a portion ofthe pyrolysis fluid, may be injected into formation 940. In some processembodiments, pyrolysis fluid 964 introduced into formation 940 mayinclude no, or substantially no, hydrocarbons having carbon numbersgreater than about 4. In other process embodiments, pyrolysis fluid 964introduced into formation 940 may include a significant portion ofhydrocarbons having carbon numbers greater than 4. In some processembodiments, pyrolysis fluid 964 introduced into formation 940 mayinclude no, or substantially no, hydrocarbons having carbon numbers lessthan 5. When hydrocarbons in pyrolysis fluid 964 are introduced intoformation 940, the hydrocarbons may crack within the formation toproduce methane, H₂, and coke.

[1317]FIG. 120 depicts an embodiment of a synthesis gas generatingprocess from relatively permeable formation 976 with Blamelessdistributed combustor 996. Synthesis gas 980 produced from productionwell 978 may be fed into gas separation plant 984. Gas separation plant984 may separate carbon dioxide 986 from other components of synthesisgas 980. First portion 990 of carbon dioxide may be routed to aformation for sequestration. Second portion 992 of carbon dioxide may beinjected into the formation with synthesis gas generating fluid. Portion993 of synthesis gas 988 from separation plant 984 may be introducedinto heater well 994 as a portion of fuel for combustion in flamelessdistributed combustor 996. Flameless distributed combustor 996 mayprovide heat to the formation. Portion 998 of synthesis gas 988 may befed to fuel cell 1000 for the production of electricity. Electricity1002 may be routed to a power grid. Steam 1004 produced in the fuel celland steam 1006 produced from combustion in the distributed burner may beintroduced into the formation as a portion of a synthesis gas generationfluid.

[1318] In an in situ conversion process embodiment, carbon dioxidegenerated with pyrolysis fluids may be sequestered in a relativelypermeable formation. FIG. 121 illustrates in situ pyrolysis inrelatively permeable formation 1020. Heat source 1022 with electricheater 1024 may be placed in formation 1020. Pyrolysis fluids 1026 maybe produced from formation 1020 and fed into gas separation unit 1028.Gas separation unit 1028 may separate pyrolysis fluid 1026 into carbondioxide 1030, vapor component 1032, and liquid component 1031. Portion1034 of carbon dioxide 1030 may be stored in formation 1036. Formation1036 may be a coal bed with entrained methane. The carbon dioxide maydisplace some of the methane and allow for production of methane. Thecarbon dioxide may be sequestered in spent relatively permeableformation 1038, injected into oil producing fields 1040 for enhanced oilrecovery, or sequestered into coal bed 1042. In some embodiments,portion 1044 of carbon dioxide 1030 may be re-injected into a section offormation 1020 through a synthesis gas production well to promoteproduction of carbon monoxide.

[1319] Vapor component 1032 and/or carbon dioxide 1030 may pass throughturbine 1033 or turbines to generate electricity. A portion ofelectricity 1035 generated by the vapor component and/or carbon dioxidemay be used to power electric heaters 1024 placed within formation 1020.Initial power and/or make-up power may be provided to electric heatersfrom a power grid.

[1320] As depicted in FIG. 122, heater well 1060 may be located withinrelatively permeable formation 1062. Additional heater wells may also belocated within formation 1062. Heater well 1060 may include electricheater 1064 or another type of heat source. Pyrolysis fluid 1066produced from the formation may be fed to reformer 1068 to producesynthesis gas 1070. In some process embodiments, reformer 1068 is asteam reformer. Synthesis gas 1070 may be sent to fuel cell 1072. Aportion of pyrolysis fluid 1060 and/or produced synthesis gas 1070 maybe used as fuel to heat steam reformer 1068. Steam reformer 1068 mayinclude a catalyst material that promotes the reforming reaction and aburner to supply heat for the endothermic reforming reaction. A steamsource may be connected to reformer 1068 to provide steam for thereforming reaction. The burner may operate at temperatures well abovethat required by the reforming reaction and well above the operatingtemperatures of fuel cells. As such, it may be desirable to operate theburner as a separate unit independent of fuel cell 1072.

[1321] In some process embodiments, reformer 1068 may be a tubereformer. Reformer 1068 may include multiple tubes made of refractorymetal alloys. Each tube may include a packed granular or pelletizedmaterial having a reforming catalyst as a surface coating. A diameter ofthe tubes may vary from between about 9 cm and about 16 cm. A heatedlength of each tube may normally be between about 6 m and about 12 m. Acombustion zone may be provided external to the tubes, and may be formedin the burner. A surface temperature of the tubes may be maintained bythe burner at a temperature of about 900° C. to ensure that thehydrocarbon fluid flowing inside the tube is properly catalyzed withsteam at a temperature between about 500° C. and about 700° C. Atraditional tube reformer may rely upon conduction and convection heattransfer within the tube to distribute heat for reforming.

[1322] Pyrolysis fluids 1066 from formation 1062 may be pre-processedprior to being fed to reformer 1068. Reformer 1068 may transformpyrolysis fluids 1066 into simpler reactants prior to introduction to afuel cell. For example, pyrolysis fluids 1066 may be pre-processed in adesulfurization unit. Subsequent to pre-processing, pyrolysis fluids1066 may be provided to a reformer and a shift reactor to produce asuitable fuel stock for a H₂ fueled fuel cell.

[1323] Synthesis gas 1070 produced by reformer 1068 may include a numberof components including carbon dioxide, carbon monoxide, methane, and/orhydrogen. Produced synthesis gas 1070 may be fed to fuel cell 1072.Portion 1074 of electricity produced by fuel cell 1072 may be sent to apower grid. In addition, portion 1076 of electricity may be used topower electric heater 1064. Carbon dioxide 1078 exiting the fuel cellmay be routed to sequestration area 1080. The sequestration area may bea spent portion of formation 1062.

[1324] In a process embodiment, pyrolysis fluid produced from aformation may be fed to the reformer. The reformer may produce carbondioxide stream and a H₂ stream. For example, the reformer may include aflameless distributed combustor for a core, and a membrane. The membranemay allow only H₂ to pass through the membrane resulting in separationof the H₂ and carbon dioxide. The carbon dioxide may be routed to asequestration area.

[1325] Synthesis gas produced from a formation may be converted toheavier condensable hydrocarbons. For example, a Fischer-Tropschhydrocarbon synthesis process may be used for conversion of synthesisgas. A Fischer-Tropsch process may include converting synthesis gas tohydrocarbons. The process may use elevated temperatures, normal orelevated pressures, and a catalyst, such as magnetic iron oxide or acobalt catalyst. Products produced from a Fischer-Tropsch process mayinclude hydrocarbons having a broad molecular weight distribution andmay include branched and/or unbranched paraffins. Products from aFischer-Tropsch process may also include considerable quantities ofolefins and oxygen containing organic compounds. An example of aFischer-Tropsch reaction may be illustrated by Reaction 30: (n+2)CO+(2n+5)H₂⇄CH₃(—CH₂—)_(n)CH₃+(n+2)H₂O  (30)

[1326] A hydrogen to carbon monoxide ratio for synthesis gas used as afeed gas for a Fischer-Tropsch reaction may be about 2:1. In certainembodiments, the ratio may range from approximately 1.8:1 to 2.2:1.Higher or lower ratios may be accommodated by certain Fischer-Tropschsystems.

[1327]FIG. 123 illustrates a flow chart of a Fischer-Tropsch processthat uses synthesis gas produced from a relatively permeable formationas a feed stream. Hot formation 1090 may be used to produce synthesisgas having a H₂ to CO ratio of approximately 2:1. The proper ratio maybe produced by operating synthesis production wells at approximately700° C., or by blending synthesis gas produced from different sectionsof formation to obtain a synthesis gas having approximately a 2:1H₂ toCO ratio. Synthesis gas generating fluid 1092 may be fed into hotformation 1090 to generate synthesis gas. H₂ and CO may be separatedfrom the synthesis gas produced from the hot formation 1090 to form feedstream 1094. Feed stream 1094 may be sent to Fischer-Tropsch plant 1096.Feed stream 1094 may supplement or replace synthesis gas 1098 producedfrom catalytic methane reformer 1100.

[1328] Fischer-Tropsch plant 1096 may produce wax feed stream 1102. TheFischer-Tropsch synthesis process that produces wax feed stream 1102 isan exothermic process. Steam 1104 may be generated during theFischer-Tropsch process. Steam 1104 may be used as a portion ofsynthesis gas generating fluid 1092.

[1329] Wax feed stream 1102 produced from Fischer-Tropsch plant 1096 maybe sent to hydrocracker 1106. Hydrocracker 1106 may produce productstream 1108. The product stream may include diesel, jet fuel, and/ornaphtha products. Examples of methods for conversion of synthesis gas tohydrocarbons in a Fischer-Tropsch process are illustrated in U.S. Pat.Nos. 4,096,163 to Chang et al., 6,085,512 to Agee et al., and 6,172,124to Wolflick et al., which are incorporated by reference as if fully setforth herein.

[1330]FIG. 124 depicts an embodiment of in situ synthesis gas productionintegrated with a Shell Middle Distillates Synthesis (SMDS)Fischer-Tropsch and wax cracking process. An example of a SMDS processis illustrated in U.S. Pat. No. 4,594,468 to Minderhoud, and isincorporated by reference as if fully set forth herein. A middledistillates hydrocarbon mixture may be produced from produced synthesisgas using the SMDS process as illustrated in FIG. 124. Synthesis gas1120, having a H₂ to carbon monoxide ratio of about 2:1, may exitproduction well 1128. The synthesis gas may be fed into SMDS plant 1122.In certain embodiments, the ratio may range from approximately 1.8:1 to2.2:1. Products of the SMDS plant include organic liquid product 1124and steam 1126. Steam 1126 may be supplied to injection wells 1127.Steam may be used as a feed for synthesis gas production. Hydrocarbonvapors may in some circumstances be added to the steam.

[1331]FIG. 125 depicts an embodiment of in situ synthesis gas productionintegrated with a catalytic methanation process. Synthesis gas 1140exiting production well 1142 may be supplied to catalytic methanationplant 1144. Synthesis gas supplied to catalytic methanation plant 1144may have a H₂ to carbon monoxide ratio of about 3:1. Methane 1146 may beproduced by catalytic methanation plant 1144. Steam 1148 produced byplant 1144 may be supplied to injection well 1141 for production ofsynthesis gas. Examples of a catalytic methanation process areillustrated in U.S. Pat. Nos. 3,922,148 to Child; 4,130,575 to Jorn etal.; and 4,133,825 to Stroud et al., which are incorporated by referenceas if fully set forth herein.

[1332] Synthesis gas produced from a formation may be used as a feed fora process for producing methanol. Examples of processes for productionof methanol are described in U.S. Pat. Nos. 4,407,973 to van Dijk etal., 4,927,857 to McShea, III et al., and 4,994,093 to Wetzel et al.,each of which is incorporated by reference as if fully set forth herein.The produced synthesis gas may also be used as a feed gas for a processthat converts synthesis gas to engine fuel (e.g., gasoline or diesel).Examples of process for producing engine fuels are described in U.S.Pat. Nos. 4,076,761 to Chang et al., 4,138,442 to Chang et al., and4,605,680 to Beuther et al., each of which is incorporated by referenceas if fully set forth herein.

[1333] In a process embodiment, produced synthesis gas may be used as afeed gas for production of ammonia and urea. FIGS. 126 and 127 depictembodiments of making ammonia and urea from synthesis gas. Ammonia maybe synthesized by the Haber-Bosch process, which involves synthesisdirectly from N₂ and H₂ according to Reaction 31:

N₂+3H₂⇄2NH₃.  (31)

[1334] The N₂ and H₂ may be combined, compressed to high pressure,(e.g., from about 80 bars to about 220 bars), and then heated to arelatively high temperature. The reaction mixture may be passed over acatalyst composed substantially of iron to produce ammonia. Duringammonia synthesis, the reactants (i.e., N₂ and H₂) and the product(i.e., ammonia) may be in equilibrium. The total amount of ammoniaproduced may be increased by shifting the equilibrium towards productformation. Equilibrium may be shifted to product formation by removingammonia from the reaction mixture as ammonia is produced.

[1335] Removal of the ammonia may be accomplished by cooling the gasmixture to a temperature between about −5° C. to about 25° C. In thistemperature range, a two-phase mixture may be formed with ammonia in theliquid phase and N₂ and H₂ in the gas phase. The ammonia may beseparated from other components of the mixture. The nitrogen andhydrogen may be subsequently reheated to the operating temperature forammonia conversion and passed through the reactor again.

[1336] Urea may be prepared by introducing ammonia and carbon dioxideinto a reactor at a suitable pressure, (e.g., from about 125 barsabsolute to about 350 bars absolute), and at a suitable temperature,(e.g., from about 160° C. to about 250° C.). Ammonium carbamate may beformed according to Reaction 32:

2NH₃+CO₂⇄NH₂(CO₂)NH₄.  (32)

[1337] Urea may be subsequently formed by dehydrating the ammoniumcarbamate according to equilibrium Reaction 33:

NH₂(CO₂)NH₄⇄NH₂(CO)NH₂+H₂O.  (33)

[1338] The degree to which the ammonia conversion takes place may dependon the temperature and the amount of excess ammonia. The solutionobtained as the reaction product may include urea, water, ammoniumcarbamate, and unbound ammonia. The ammonium carbamate and the ammoniamay need to be removed from the solution and returned to the reactor.The reactor may include separate zones for the formation of ammoniumcarbamate and urea. However, these zones may also be combined into onepiece of equipment.

[1339] In a process embodiment, a high pressure urea plant may operatesuch that the decomposition of ammonium carbamate that has not beenconverted into urea and the expulsion of the excess ammonia areconducted at a pressure between 15 bars absolute and 100 bars absolute.This pressure may be considerably lower than the pressure in the ureasynthesis reactor. The synthesis reactor may be operated at atemperature of about 180° C. to about 210° C. and at a pressure of about180 bars absolute to about 300 bars absolute. Ammonia and carbon dioxidemay be directly fed to the urea reactor. The NH₃/CO₂ molar ratio (N/Cmolar ratio) in the urea synthesis may generally be between about 3 andabout 5. The unconverted reactants may be recycled to the urea synthesisreactor following expansion, dissociation, and/or condensation.

[1340] In a process embodiment, an ammonia feed stream having a selectedratio of H₂ to N₂ may be generated from a formation using enriched air.A synthesis gas generating fluid and an enriched air stream may beprovided to the formation. The composition of the enriched air may beselected to generate synthesis gas having the selected ratio of H₂ toN₂. In one embodiment, the temperature of the formation may becontrolled to generate synthesis gas having the selected ratio.

[1341] In a process embodiment, the H₂ to N₂ ratio of the feed streamprovided to the ammonia synthesis process may be approximately 3:1. Inother embodiments, the ratio may range from approximately 2.8:1 to3.2:1. An ammonia synthesis feed stream having a selected H₂ to N₂ ratiomay be obtained by blending feed streams produced from differentportions of the formation.

[1342] In a process embodiment, ammonia from the ammonia synthesisprocess may be provided to a urea synthesis process to generate urea.Ammonia produced during pyrolysis may be added to the ammonia generatedfrom the ammonia synthesis process. In another process embodiment,ammonia produced during hydrotreating may be added to the ammoniagenerated from the ammonia synthesis process. Some of the carbonmonoxide in the synthesis gas may be converted to carbon dioxide in ashift process. The carbon dioxide from the shift process may be fed tothe urea synthesis process. Carbon dioxide generated from treatment ofthe formation may also be fed, in some embodiments, to the ureasynthesis process.

[1343]FIG. 126 illustrates an embodiment of a method for production ofammonia and urea from synthesis gas using membrane-enriched air.Enriched air 1170 and steam, or water, 1172 may be fed into hot carboncontaining formation 1174 to produce synthesis gas 1176 in a wetoxidation mode.

[1344] In some synthesis gas production embodiments, enriched air 1170is blended from air and oxygen streams such that the nitrogen tohydrogen ratio in the produced synthesis gas is about 1:3. The synthesisgas may be at a correct ratio of nitrogen and hydrogen to form ammonia.For example, it has been calculated that for a formation temperature of700° C., a pressure of 3 bars absolute, and with 13,231 tons/day of charthat will be converted into synthesis gas, one could inject 14.7kilotons/day of air, 6.2 kilotons/day of oxygen, and 21.2 kilotons/dayof steam. This would result in production of 2 billion cubic feet/day ofsynthesis gas including 5689 tons/day of steam, 16,778 tons/day ofcarbon monoxide, 1406 tons/day of hydrogen, 18,689 tons/day of carbondioxide, 1258 tons/day of methane, and 11,398 tons/day of nitrogen.After a shift reaction (to shift the carbon monoxide to carbon dioxideand to produce additional hydrogen), the carbon dioxide may be removed,the product stream may be methanated (to remove residual carbonmonoxide), and then one can theoretically produce 13,840 tons/day ofammonia and 1258 tons/day of methane. This calculation includes theproducts produced from Reactions (27) and (28) above.

[1345] Enriched air may be produced from a membrane separation unit.Membrane separation of air may be primarily a physical process. Basedupon specific characteristics of each molecule, such as size andpermeation rate, the molecules in air may be separated to formsubstantially pure forms of nitrogen, oxygen, or combinations thereof.

[1346] In a membrane system embodiment, the membrane system may includea hollow tube filled with a plurality of very thin membrane fibers. Eachmembrane fiber may be another hollow tube in which air flows. The wallsof the membrane fiber may be porous such that oxygen permeates throughthe wall at a faster rate than nitrogen. A nitrogen rich stream may beallowed to flow out the other end of the fiber. Air outside the fiberand in the hollow tube may be oxygen enriched. Such air may be separatedfor subsequent uses, such as production of synthesis gas from aformation.

[1347] In some membrane system embodiments, the purity of nitrogengenerated may be controlled by variation of the flow rate and/orpressure of air through the membrane. Increasing air pressure mayincrease permeation of oxygen molecules through a fiber wall. Decreasingflow rate may increase the residence time of oxygen in the membrane and,thus, may increase permeation through the fiber wall. Air pressure andflow rate may be adjusted to allow a system operator to vary the amountand purity of the nitrogen generated in a relatively short amount oftime.

[1348] The amount of N₂ in the enriched air may be adjusted to provide aN:H ratio of about 3:1 for ammonia production. Synthesis gas may begenerated at a temperature that favors the production of carbon dioxideover carbon monoxide. The temperature during synthesis gas may bemaintained between about 400° C. and about 550° C., or between about400° C. and about 450° C. Synthesis gas produced at such lowtemperatures may include N₂, H₂, and carbon dioxide with little carbonmonoxide.

[1349] As illustrated in FIG. 126, a feed stream for ammonia productionmay be prepared by first feeding synthesis gas stream 1176 into ammoniafeed stream gas processing unit 1178. In ammonia feed stream gasprocessing unit 1178, the feed stream may undergo a shift reaction (toshift the carbon monoxide to carbon dioxide and to produce additionalhydrogen). Carbon dioxide may be removed from the feed stream, and thefeed stream can be methanated (to remove residual carbon monoxide). Incertain embodiments, carbon dioxide may be separated from the feedstream (or any gas stream) by absorption in an amine unit. Membranes orother carbon dioxide separation techniques/equipment may also be used toseparate carbon dioxide from a feed stream.

[1350] Ammonia feed stream 1180 may be fed to ammonia productionfacility 1182 to produce ammonia 1184. Carbon dioxide 1186 exiting gasseparation unit 1178 (and/or carbon dioxide from other sources) may befed, with ammonia 1184, into urea production facility 1188 to produceurea 1190.

[1351] Ammonia and urea may be produced using a formation and using anO₂ rich stream and a N₂ rich stream. The O₂ rich stream and synthesisgas generating fluid may be provided to a formation. The formation maybe heated, or partially heated, by oxidation of carbon in the formationwith the O₂ rich stream. H₂ in the synthesis gas and N₂ from the N₂ richstream may be provided to an ammonia synthesis process to generateammonia.

[1352]FIG. 127 illustrates a flow chart of an embodiment for productionof ammonia and urea from synthesis gas using cryogenically separatedair. Air 2000 may be fed into cryogenic air separation unit 2002.Cryogenic separation involves a distillation process that may occur attemperatures between about −168° C. and −172° C. In other embodiments,the distillation process may occur at temperatures between about −165°C. and −175° C. Air may liquefy in these temperature ranges. Thedistillation process may be operated at a pressure between about 8 barsabsolute and about 10 bars absolute. High pressures may be achieved bycompressing air and exchanging heat with cold air exiting the column.Nitrogen is more volatile than oxygen and may come off as a distillateproduct.

[1353] N₂ 2004 exiting separator 2002 may be utilized in heat exchanger2006 to condense higher molecular weight hydrocarbons from pyrolysisstream 2008 and to remove lower molecular weight hydrocarbons from thegas phase into a liquid oil phase. Upgraded gas stream 2010 containing ahigher composition of lower molecular weight hydrocarbons than stream2008 and liquid stream 2012, which includes condensed hydrocarbons, mayexit heat exchanger 2006. N₂ 2004 may also exit heat exchanger 2006.

[1354] Oxygen 2014 from cryogenic separation unit 2002 and steam 2016,or water, may be fed into hot carbon containing formation 2018 toproduce synthesis gas 2020 in a continuous process. Synthesis gas may begenerated at a temperature that favors the formation of carbon dioxideover carbon monoxide. Synthesis gas 2020 may include H₂ and carbondioxide. Carbon dioxide may be removed from synthesis gas 2020 toprepare a feed stream for ammonia production using amine gas separationunit 2022. H₂ stream 2024 from gas separation unit 2022 and N₂ stream2004 from the heat exchanger may be fed into ammonia production facility2028 to produce ammonia 2030. Carbon dioxide 2032 exiting gas separationunit 2022 and ammonia 2030 may be fed into urea production facility 2034to produce urea 2036.

[1355]FIG. 128 illustrates an embodiment of a method for preparing anitrogen stream for an ammonia and urea process. Air 2060 may beinjected into hot carbon containing formation 2062 to produce carbondioxide by oxidation of carbon in the formation. In an embodiment, aheater may heat at least a portion of the carbon containing formation toa temperature sufficient to support oxidation of the carbon. Stream 2064exiting the hot formation may include carbon dioxide and nitrogen. Insome embodiments, a flue gas stream may be added to stream 2064, orstream 2064 may be a flue gas stream instead of a stream from a portionof a formation.

[1356] Nitrogen may be separated from carbon dioxide in stream 2064 bypassing the stream through cold spent carbon containing formation 2066.Carbon dioxide may preferentially adsorb versus nitrogen in cold spentformation 2066. Nitrogen 2068 exiting cold spent portion 2066 may besupplied to ammonia production facility 2070 with H₂ stream 2072 toproduce ammonia 2074. In some process embodiments, H₂ stream 2072 may beobtained from a product stream produced during synthesis gas generationof a portion of the formation.

[1357]FIG. 129 depicts an embodiment for treating a relatively permeableformation using horizontal heat sources. Heat source 2300 may bedisposed within hydrocarbon layer 2200. Hydrocarbon layer 2200 may bebelow layer 2204 (e.g., an overburden). Layer 2204 may include, but isnot limited to, shale, carbonate, and/or other types of sedimentaryrock. Layer 2204 may have a thickness of about 10 m or more. A thicknessof layer 2204, however, may vary depending on, for example, a type offormation. Heat source 2300 may be disposed substantially horizontallyor, in some embodiments, at an angle between horizontal and verticalwithin hydrocarbon layer 2200. Heat source 2300 may provide heat to aportion of hydrocarbon layer 2200.

[1358] Heat source 2300 may include a low temperature heat source and/ora high temperature heat source. Provided heat may mobilize a portion ofheavy hydrocarbons within hydrocarbon layer 2200. Provided heat may alsopyrolyze a portion of heavy hydrocarbons within hydrocarbon layer 2200.A length of horizontal heat source 2300 disposed within hydrocarbonlayer 2200 may be between about 50 m to about 1500 m. The length of heatsource 2300 within hydrocarbon layer 2200 may vary, however, dependingon, for example, a width of hydrocarbon layer 2200, a desired productionrate, an energy output of heat source 2300, and/or a maximum possiblelength of a wellbore and/or heat sources.

[1359]FIG. 130 depicts an embodiment for treating a relatively permeableformation using substantially horizontal heat sources. Heat sources 2300may be disposed horizontally within hydrocarbon layer 2200. Hydrocarbonlayer 2200 may be below layer 2204. Production well 2302 may be disposedvertically, horizontally, or at an angle to hydrocarbon layer 2200. Thelocation of production well 2302 within hydrocarbon layer 2200 may varydepending on a variety of factors (e.g., a desired product and/or adesired production rate). In certain embodiments, production well 2302may, in certain embodiments, be disposed proximate a bottom ofhydrocarbon layer 2200. Producing proximate the bottom of the relativelypermeable formation may allow for production of a relatively low APIgravity fluid. In other embodiments, production well 2302 may bedisposed proximate a top of hydrocarbon layer 2200. Producing proximatethe top of the relatively permeable formation may allow for productionof a relatively high API gravity fluid.

[1360] Heat sources 2300 may provide heat to mobilize a portion of theheavy hydrocarbons within hydrocarbon layer 2200. The mobilized fluidsmay flow towards a bottom of hydrocarbon layer 2200 substantially bygravity. The mobilized fluids may be removed through production well2302. Each of heat sources 2300 disposed at or near the bottom ofhydrocarbon layer 2200 may heat some or all of a section proximate thebottom of hydrocarbon layer 2200 to a temperature sufficient to pyrolyzeheavy hydrocarbons within the section. Such a section may be referred toas a selected pyrolyzation section. A temperature within the selectedpyrolyzation section may be between about 225° C. and about 400° C.Pyrolysis of the heavy hydrocarbons within the selected pyrolyzationsection may convert a portion of the heavy hydrocarbons intopyrolyzation fluids. The pyrolyzation fluids may be removed throughproduction well 2302. Production well 2302 may be disposed within theselected pyrolyzation section. In some embodiments, one or more of heatsources 2300 may be turned down and/or off after substantiallymobilizing a majority of the heavy hydrocarbons within hydrocarbon layer2200. Doing so may more efficiently heat the formation and/or may saveinput energy costs associated with the in situ process. In addition, theformation may be heated during off peak times when electricity ischeaper, if the heaters are electric heaters.

[1361] In certain embodiments, heat may be provided within productionwell 2302 to vaporize formation fluids. Heat may also be provided withinproduction well 2302 to pyrolyze and/or upgrade formation fluids.

[1362] In some embodiments, a pressurizing fluid may be provided intohydrocarbon layer 2200 through heat sources 2300. The pressurizing fluidmay increase the flow of the mobilized fluids towards production well2302. Increasing the pressure of the pressurizing fluid proximate heatsources 2300 will tend to increase the flow of the mobilized fluidstowards production well 2302. The pressurizing fluid may include, but isnot limited to, steam, N₂, CO₂, CH₄, H₂, combustion products, anon-condensable or condensable component of fluid produced from theformation, by-products of surface processes such as refining orpower/heat generation, and/or mixtures thereof. Alternatively, thepressurizing fluid may be provided through an injection well disposed inthe formation.

[1363] Pressure in the formation may be controlled to control aproduction rate of formation fluids from the formation. The pressure inthe formation may be controlled by adjusting control valves coupled toproduction wells 2302, heat sources 2300, and/or pressure control wellsdisposed in the formation.

[1364] In an embodiment, an in situ process for treating a relativelypermeable formation may include providing heat to a portion of aformation from a plurality of heat sources. A plurality of heat sourcesmay be arranged within a relatively permeable formation in a pattern.FIG. 131 illustrates an embodiment of pattern 2404 of heat sources 2400and production well 2402 that may treat a relatively permeableformation. Heat sources 2400 may be arranged in a “5 spot” pattern withproduction well 2402. In the “5 spot” pattern, four heat sources 2400are arranged substantially around production well 2402, as depicted inFIG. 131. Although heat sources 2400 are depicted as being equidistantfrom each other in FIG. 131, the heat sources may be placed aroundproduction well 2402 and not be equidistant from the production welland/or each other. Depending on the heat generated by each heat source2400, a spacing between heat sources 2400 and production well 2402 maybe determined by a desired product or a desired production rate. Aspacing between heat sources 2400 and production well 2402 may be, forexample, about 15 m. A heat source 2400 may be converted into productionwell 2402. A production well 2402 may be converted into a heat source2400.

[1365]FIG. 132 illustrates an alternate embodiment of pattern 2406 ofheat sources 2400 arranged in a “7 spot” pattern with production well2402. In the “7 spot” pattern, six heat sources 2400 are arrangedsubstantially around production well 2402, as depicted in FIG. 132.Although heat sources 2400 are depicted as being equidistant from eachother in FIG. 132, the heat sources may be placed around production well2402 and not be equidistant from the production well and/or each other.Heat sources 2400 may also be used to produce fluids from the formation.In addition, production well 2402 may be heated.

[1366] In certain embodiments, a pattern of heat sources 2400 andproduction wells 2402 may vary depending on, for example, the type ofrelatively permeable formation to be treated. A location of productionwell 2402 within a pattern of heat sources 2400 may be determined by,for example, a desired heating rate of the relatively permeableformation, a heating rate of the heat sources, a type of heat source, atype of relatively permeable formation, a composition of the relativelypermeable formation, a viscosity of fluid in the relatively permeableformation, and/or a desired production rate.

[1367]FIG. 133 illustrates a plan view of an embodiment for treating arelatively permeable formation. Hydrocarbon layer 2200 may include heavyhydrocarbons. Production wells 2210 may be disposed in hydrocarbon layer2200. Hydrocarbon layer 2200 may be enclosed between impermeable layers.Upper impermeable layer 2204 may be referred to as an overburden. Lowerimpermeable layer 2203 may be referred to as an underburden or a baserock. In some embodiments, the overburden and/or the underburden may besomewhat permeable.

[1368] In an embodiment, low temperature heat sources 2216 and hightemperature heat sources 2218 are disposed in production well 2210. Lowtemperature heat source 2216 may be a heat source, or heater, thatprovides heat to a selected mobilization section of hydrocarbon layer2200, which is substantially adjacent to low temperature heat source2216. The provided heat may heat some or all of the selectedmobilization section to an average temperature within a mobilizationtemperature range of the heavy hydrocarbons contained within hydrocarbonlayer 2200. The mobilization temperature range may be between about 50°C. and about 225° C. A selected mobilization temperature may be about100° C. The mobilization temperature may vary, however, depending on aviscosity of the heavy hydrocarbons contained within hydrocarbon layer2200. For example, a higher mobilization temperature may be required tomobilize a higher viscosity fluid within hydrocarbon layer 2200.

[1369] High temperature heat source 2218 may be a heat source, orheater, that provides heat to selected pyrolyzation section 2202 ofhydrocarbon layer 2200, which may be substantially adjacent to the hightemperature heat source. The provided heat may heat some or all ofselected pyrolyzation section 2202 to an average temperature within apyrolyzation temperature range of the heavy hydrocarbons containedwithin hydrocarbon layer 2200. The pyrolyzation temperature range may bebetween about 225° C. and about 400° C. A selected pyrolyzationtemperature may be about 300° C. The pyrolyzation temperature may vary,however, depending on formation characteristics, composition, pressure,and/or a desired quality of a product produced from the formation. Aquality of the product may be determined based upon properties of theproduct (e.g., the API gravity of the product). Pyrolyzation may includecracking of the heavy hydrocarbons into hydrocarbon fragments and/orlighter hydrocarbons. Pyrolyzation of the heavy hydrocarbons tends toupgrade the quality of the heavy hydrocarbons.

[1370] As shown in FIG. 133, mobilized fluids in hydrocarbon layer 2200may flow into selected pyrolyzation section 2202 substantially bygravity. The mobilized fluids may be upgraded by pyrolysis in selectedpyrolyzation section 2202. Flow of the mobilized fluids may optionallybe increased by providing pressurizing fluid 2214 (e.g., through conduit2212 or any injection well placed in the formation) into the formation.Pressurizing fluid 2214 may be a fluid that increases a pressure in theformation proximate conduit 2212. The increased pressure proximateconduit 2212 may increase flow of the mobilized fluids in hydrocarbonlayer 2200 into selected pyrolyzation section 2202. A pressure ofpressurizing fluid 2214 provided by conduit 2212 may be between, in oneembodiment, about 7 bars absolute to about 70 bars absolute. Thepressure of pressurizing fluid 2214 may vary, however, depending on, forexample, a viscosity of fluid within hydrocarbon layer 2200, the depthof layer 2204, and/or a desired flow rate of fluid into selectedpyrolyzation section 2202. Pressurizing fluid 2214 may, in certainembodiments, be any gas that does not result in significant oxidation ofthe heavy hydrocarbons. For example, pressurizing fluid 2214 may includesteam, N₂, CO₂, CH₄, hydrogen, etc.

[1371] Production wells 2210 may remove pyrolyzation fluids and/ormobilized fluids from selected pyrolyzation section 2202. In someembodiments, formation fluids may be removed as vapor. The formationfluids may be upgraded by reactions induced by high temperature heatsource 2218 and/or low temperature heat source 2216 in production well2210. Production well 2210 may control pressure in selected pyrolyzationsection 2202 to provide a pressure gradient so that mobilized fluidsflow into selected pyrolyzation section 2202 from the selectedmobilization section. In some embodiments, pressure in selectedpyrolyzation section 2202 may be controlled to control the flow of themobilized fluids into selected pyrolyzation section 2202. By not heatingthe entire formation to pyrolyzation temperatures, the drainage processmay produce a higher ratio of energy produced versus energy input forthe in situ conversion process (as compared to heating the entireformation to pyrolysis temperatures).

[1372] In addition, pressure in the formation may be controlled toproduce a desired quality of formation fluids. For example, the pressurein the formation may be increased to produce formation fluids with anincreased API gravity as compared to formation fluids produced at alower pressure. Increasing the pressure in the formation may increase ahydrogen partial pressure in mobilized and/or pyrolyzation fluids. Theincreased hydrogen partial pressure in mobilized and/or pyrolyzationfluids may reduce the heavy hydrocarbons in mobilized and/orpyrolyzation fluids. Reducing the heavy hydrocarbons may producelighter, more valuable hydrocarbons. An API gravity of the hydrogenatedheavy hydrocarbons may be higher than an API gravity of theun-hydrogenated heavy hydrocarbons.

[1373] In an embodiment, pressurizing fluid 2214 may be provided to theformation through a conduit disposed in/or proximate production well2210. The conduit may provide pressurizing fluid 2214 into hydrocarbonlayer 2200 proximate layer 2204. In some embodiments, the conduit is aninjection well.

[1374] In another embodiment, low temperature heat source 2216 may beturned down and/or off in production wells 2210. The heavy hydrocarbonsin hydrocarbon layer 2200 may be mobilized by transfer of heat fromselected pyrolyzation section 2202 into an adjacent portion ofhydrocarbon layer 2200. Heat transfer from selected pyrolyzation section2202 may be substantially by conduction.

[1375]FIG. 134 illustrates an embodiment for treating a relativelypermeable formation without substantially pyrolyzing mobilized fluids.Low temperature heat source 2216 may be placed in production well 2210.Low temperature heat source 2216 may provide heat to hydrocarbon layer2200 to heat some or all of hydrocarbon layer 2200 to an averagetemperature within the mobilization temperature range. Mobilized fluidswithin hydrocarbon layer 2200 may flow towards a bottom of hydrocarbonlayer 2200 substantially by gravity. Pressurizing fluid 2214 may beprovided into the formation through conduit 2212 and may increase a flowof the mobilized fluids towards the bottom of hydrocarbon layer 2200.Pressurizing fluid 2214 may also be provided into the formation throughanother conduit, such as a conduit disposed in/or proximate productionwell 2210. Formation fluids may be removed through production well 2210at and/or near the bottom of hydrocarbon layer 2200. Low temperatureheat source 2216 may provide heat to the formation fluids removedthrough production well 2210. The provided heat may vaporize the removedformation fluids within production well 2210 such that the formationfluids may be removed as a vapor. The provided heat may also increase anAPI gravity of the removed formation fluids within production well 2210.

[1376]FIG. 135 illustrates an embodiment for treating a relativelypermeable formation with layers 2201 of heavy hydrocarbons separated bylayers 2204. Such layers 2204 may, for example, be impermeable layers orless permeable layers of the formation. Heat injection well 2220 andproduction well 2210 may be disposed in hydrocarbon layer 2200. Layers2204 may separate layers 2201. Heavy hydrocarbons may be disposed inlayers 2201. Low temperature heat source 2216 may be disposed ininjection well 2220. Heavy hydrocarbons may be mobilized by heatprovided from low temperature heat source 2216 such that a viscosity ofthe heavy hydrocarbons is substantially reduced. Pressurizing fluid 2214may be provided through openings in injection well 2220 into layers2201. The pressure of pressurizing fluid 2214 may cause the mobilizedfluids to flow towards production well 2210. The pressure ofpressurizing fluid 2214 at or near injection well 2220 may be, forexample, about 7 bars absolute to about 70 bars absolute. The pressureof pressurizing fluid 2214 is, however, generally controlled to remainbelow a pressure that can lift the overburden.

[1377] High temperature heat source 2218 may, in some embodiments, bedisposed in production well 2210. Heat provided by high temperature heatsource 2218 may pyrolyze a portion of the mobilized fluids within aselected pyrolyzation section proximate production well 2210. Thepyrolyzation and/or mobilized fluids may be removed from layers 2201 byproduction well 2210. High temperature heat source 2218 may causereactions that further upgrade the removed formation fluids withinproduction well 2210. In some embodiments, the removed formation fluidsmay be removed as vapor through production well 2210. A pressure at ornear production well 2210 may be less than about 70 bars absolute. Notheating the entire formation to pyrolyzation temperatures may produce ahigher ratio of energy produced versus energy input for the in situconversion process as compared to heating the entire formation topyrolysis temperatures. Upgrading of the formation fluids at or nearproduction well 2210 may produce a higher value product.

[1378] In another embodiment, high temperature heat source 2218 may besupplemented or replaced with low temperature heat source 2216 withinproduction well 2210. Low temperature heat source 2216 may produce lesspyrolyzation of the heavy hydrocarbons within layers 2201 than hightemperature heat source 2218. Therefore, the formation fluids removedthrough production well 2210 produced with low temperature heat source2216 may not be as upgraded as formation fluids removed throughproduction well 2210 produced with high temperature heat source 2218.

[1379] In another embodiment, pyrolyzation of the heavy hydrocarbons maybe increased by replacing low temperature heat source 2216 with hightemperature heat source 2218 within injection well 2220. Hightemperature heat source 2218 may allow for more pyrolyzation of theheavy hydrocarbons within layers 2201 than low temperature heat source2216. The formation fluids removed through production well 2210 may behigher in value as compared to the formation fluids removed in a processusing low temperature heat source 2216 within injection well 2220 asdescribed in the embodiment shown in FIG. 135.

[1380] In some embodiments, a relatively permeable formation may bebelow a thick impermeable layer (overburden). The overburden may have athickness ranging from about m to about 300 m or more. The overburdenmay inhibit vapor release to the atmosphere.

[1381] In some embodiments, portions of heat sources may be placedhorizontally or non-vertically in a relatively permeable formation.Using horizontal or directionally drilled heat sources may be moreeconomical than using vertical or substantially vertical heat sources.

[1382] Portions of production wells may also be disposed horizontally ornon-vertically within the relatively permeable formation.

[1383] In an embodiment, production of hydrocarbons from a formation isinhibited until at least some hydrocarbons within the formation havebeen pyrolyzed. A mixture may be produced from the formation at a timewhen the mixture includes a selected quality in the mixture (e.g., APIgravity, hydrogen concentration, aromatic content, etc.). In someembodiments, the selected quality includes an API gravity of at leastabout 20°, 30°, or 40°. Inhibiting production until at least somehydrocarbons are pyrolyzed may increase conversion of heavy hydrocarbonsto light hydrocarbons. Inhibiting initial production may minimize theproduction of heavy hydrocarbons from the formation. Production ofsubstantial amounts of heavy hydrocarbons may require expensiveequipment and/or reduce the life of production equipment.

[1384] In one embodiment, the time for beginning production may bedetermined by sampling a test stream produced from the formation. Thetest stream may be an amount of fluid produced through a production wellor a test well. The test stream may be a portion of fluid removed fromthe formation to control pressure within the formation. The test streammay be tested to determine if the test stream has a selected quality.For example, the selected quality may be a selected minimum API gravityor a selected maximum weight percentage of heavy hydrocarbons. When thetest stream has the selected quality, production of the mixture may bestarted through production wells and/or heat sources in the formation.

[1385] In an embodiment, the time for beginning production is determinedfrom laboratory experimental treatment of samples obtained from theformation. For example, a laboratory treatment may include a pyrolysisexperiment used to determine a process time that produces a selectedminimum API gravity from the sample.

[1386] In one embodiment, measuring a pressure (e.g., a downholepressure in a production well) is used to determine the time forbeginning production from a formation. For example, production may bestarted when a minimum selected downhole pressure is reached in aproduction well in a selected section of the formation.

[1387] In an embodiment, the time for beginning production is determinedfrom a simulation for treating the formation. The simulation may be acomputer simulation that simulates formation conditions (e.g., pressure,temperature, production rates, etc.) to determine qualities in fluidsproduced from the formation.

[1388] When production of hydrocarbons from the formation is inhibited,the pressure in the formation tends to increase with temperature in theformation because of thermal expansion and/or phase change of heavyhydrocarbons and other fluids (e.g., water) in the formation. Pressurewithin the formation may have to be maintained below a selected pressureto inhibit unwanted production, fracturing of the overburden orunderburden, and/or coking of hydrocarbons in the formation. Theselected pressure may be a lithostatic or hydrostatic pressure of theformation. For example, the selected pressure may be about 150 barsabsolute or, in some embodiments, the selected pressure may be about 35bars absolute. The pressure in the formation may be controlled bycontrolling production rate from production wells in the formation. Inother embodiments, the pressure in the formation is controlled byreleasing pressure through one or more pressure relief wells in theformation. Pressure relief wells may be heat sources or separate wellsinserted into the formation. Formation fluid removed from the formationthrough the relief wells may be sent to a surface facility. Producing atleast some hydrocarbons from the formation may inhibit the pressure inthe formation from rising above the selected pressure.

[1389] In certain embodiments, some formation fluids may be backproduced through a heat source wellbore. For example, some formationfluids may be back produced through a heat source wellbore during earlytimes of heating of a relatively permeable formation. In an embodiment,some formation fluids may be produced through a portion of a heat sourcewellbore. Injection of heat may be adjusted along the length of thewellbore so that fluids produced through the wellbore are notoverheated. Fluids may be produced through portions of the heat sourcewellbore that are at lower temperatures than other portions of thewellbore.

[1390] Producing at least some formation fluids through a heat sourcewellbore may reduce or eliminate the need for additional productionwells in a formation. In addition, pressures within the formation may bereduced by producing fluids through a heat source wellbore (especiallywithin the region surrounding the heat source wellbore). Reducingpressures in the formation may alter the ratio of produced liquids toproduced vapors. In certain embodiments, producing fluids through theheat source wellbore may lead to earlier production of fluids from theformation. Portions of the formation closest to the heat source wellborewill increase to mobilization and/or pyrolysis temperatures earlier thanportions of the formation near production wells. Thus, fluids may beproduced at earlier times from portions near the heat source wellbore.

[1391]FIG. 136 depicts an embodiment of a heater well for selectivelyheating a formation. Heat source 9628 may be placed in opening 514 inhydrocarbon layer 516. In certain embodiments, opening 514 may be asubstantially horizontal opening within hydrocarbon layer 516.Perforated casing 9636 may be placed in opening 514. Perforated casing9636 may provide support from hydrocarbon and/or other material inhydrocarbon layer 516 collapsing opening 514. Perforations in perforatedcasing 9636 may allow for fluid flow from hydrocarbon layer 516 intoopening 514. Heat source 9628 may include hot portion 9622. Hot portion9622 may be a portion of heat source 9628 that operates at higher heatoutputs of a heat source. For example, hot portion 9622 may outputbetween about 650 watts per meter and about 1650 watts per meter. Hotportion 9622 may extend from a “heel” of the heat source to the end ofthe heat source (i.e., the “toe” of the heat source). The heel of a heatsource is the portion of the heat source closest to the point at whichthe heat source enters a hydrocarbon layer. The toe of a heat source isthe end of the heat source furthest from the entry of the heat sourceinto a hydrocarbon layer.

[1392] In an embodiment, heat source 9628 may include warm portion 9624.Warm portion 9624 may be a portion of heat source 9628 that operates atlower heat outputs than hot portion 9622. For example, warm portion 9624may output between about 150 watts per meter and about 650 watts permeter. Warm portion 9624 may be located closer to the heel of heatsource 9628. In certain embodiments, warm portion 9624 may be atransition portion (i.e., a transition conductor) between hot portion9622 and overburden portion 9626. Overburden portion 9626 may be locatedwithin overburden 540. Overburden portion 9626 may provide a lower heatoutput than warm portion 9624. For example, overburden portion mayoutput between about 30 watts per meter and about 90 watts per meter. Insome embodiments, overburden portion 9626 may provide as close to noheat (0 watts per meter) as possible to overburden 540. Some heat,however, may be used to maintain fluids produced through opening 514 ina vapor phase within overburden 540.

[1393] In certain embodiments, hot portion 9622 of heat source 9628 mayheat hydrocarbons to high enough temperatures to result in coke 9630forming in hydrocarbon layer 516. Coke 9630 may occur in an areasurrounding opening 514. Warm portion 9624 may be operated at lower heatoutputs such that coke does not form at or near the warm portion of heatsource 9628. Coke 9630 may extend radially from opening 514 as heat fromheat source 9628 transfers outward from the opening. At a certaindistance, however, coke 9630 no longer forms because temperatures inhydrocarbon layer 516 at the certain distance will not reach cokingtemperatures. The distance at which no coke forms may be a function ofheat output (watts per meter from heat source 9628), type of formation,hydrocarbon content in the formation, and/or other conditions within theformation.

[1394] The formation of coke 9630 may inhibit fluid flow into opening514 through the coking. Fluids in the formation may, however, beproduced through opening 514 at the heel of heat source 9628 (i.e., atwarm portion 9624 of the heat source) where there is no coke formation.The lower temperatures at the heel of heat source 9628 may reduce thepossibility of increased cracking of formation fluids produced throughthe heel. Fluids may flow in a horizontal direction through theformation more easily than in a vertical direction. Typically,horizontal permeability in a relatively permeable formation (e.g., a tarsands formation) is about 5 to 10 times greater than verticalpermeability. Thus, fluids may flow along the length of heat source 9628in a substantially horizontal direction. Producing formation fluidsthrough opening 514 may be possible at earlier times than producingfluids through production wells in hydrocarbon layer 516. The earlierproduction times through opening 514 may be possible becausetemperatures near the opening increase faster than temperatures furtheraway due to conduction of heat from heat source 9628 through hydrocarbonlayer 516. Early production of formation fluids may be used to maintainlower pressures in hydrocarbon layer 516 during start-up heating of theformation (i.e., before production begins at production wells in theformation). Lower pressures in the formation may increase liquidproduction from the formation. In addition, producing formation fluidsthrough opening 514 may reduce the number of production wells needed inthe formation.

[1395] Alternately, in certain embodiments portions of a heater may bemoved or removed, thereby shortening the heated section. For example, ina horizontal well the heater may initially extend to the “toe.” Asproducts are produced from the formation, the heater may be moved sothat it is placed at location further from the “toe.” Heat may beapplied to a different portion of the formation.

[1396] In an embodiment for treating a relatively permeable formation,mobilized fluids may be produced from the formation with limited or nopyrolyzing and/or upgrading of the mobilized fluids. The produced fluidsmay be further treated in a surface facility located near the formationor at a remotely located surface facility. The produced fluids may betreated such that the fluids can be transported (e.g., by pipeline,ship, etc.). Heat sources in such an embodiment may have a largerspacing than may be needed for producing pyrolyzed formation fluids. Forexample, a spacing between heat sources may be about 15 m, about 30 m,or even about 40 m for producing substantially un-pyrolyzed fluids froma relatively permeable formation. An average temperature of theformation may be between about 50° C. and about 225° C., or, in someembodiments, between about 150° C. and about 200° C. or between about100° C. and about 150° C. For example, a well spacing of about 30 m mayproduce an average temperature in the formation of about 150° C. inabout ten years, assuming a constant heat output from the heat sources.Smaller heat source spacings may be used to increase a temperature risewithin the formation. For example, a well spacing of about 15 m willtend to produce an average temperature in the formation of about 150° C.in less than about a year. Larger well spacings may decrease costsassociated with, but not limited to, forming wellbores, purchasing andinstalling heating equipment, and providing energy to heat theformation.

[1397] In certain embodiments, the average temperature of a relativelypermeable formation is kept below the boiling point of water atformation conditions (e.g., formation pressure) in order to limit theenthalpy of vaporization loss to boiling the water. Production wells mayalso be operated to minimize the production of steam from the formation.

[1398] In some embodiments, the ratio of energy output of the formationto energy input into the formation may be increased by producing alarger percentage of heavy hydrocarbons versus light hydrocarbons fromthe formation. The energy content of heavy hydrocarbons tends to behigher than the energy content of light hydrocarbons. Producing moreheavy hydrocarbons may increase the ratio of energy output to energyinput. In addition, production costs (such as heat input) for heavyhydrocarbons from a relatively permeable formation may be less thanproduction costs for light hydrocarbons. In certain embodiments, theenergy output to energy input ratio is at least about 5. In otherembodiments, the energy output to energy input ratio is at least about 6or at least about 7. In general, energy output to energy input ratiosfor in situ production from a relatively permeable formation may beimproved versus typical production techniques. For example, steamproduction of heavy hydrocarbons typically have energy ratios betweenabout 2.7 and about 3.3. Steam production may also produce about 28% toabout 40% of the initial hydrocarbons in place from the formation. Insitu production from a relatively permeable formation may produce, incertain embodiments, greater than about 50% of the initial hydrocarbonsin place.

[1399] “Hot zones” (or “hot sections”) may be created in a formation toallow for production of hydrocarbons from the formation. Hydrocarbonfluids that are originally in the hot zones may be produced at atemperature that mobilizes the fluids within the hot zones. Removingfluids from the hot zone may create a pressure or flow gradient thatallows mobilized fluids from other zones (or sections) of the formationto flow into the hot zones when the other zones are heated tomobilization temperatures. The one or more hot zones may be heated to atemperature for pyrolyzation of hydrocarbons that flow into the hotzones. Temperatures in other zones of the formation may only be highenough such that fluids within the other zones are mobilized and flowinto the hot zones. Maintaining lower temperatures within these otherzones may reduce energy costs associated with heating a relativelypermeable formation compared to heating the entire formation (includinghot zones and other zones) to pyrolyzation temperatures. In addition,producing fluids from the one or more hot zones rather than throughoutthe formation reduces costs associated with installation and operationof production wells.

[1400]FIG. 137 depicts a cross-sectional representation of an embodimentfor treating a formation containing heavy hydrocarbons with multipleheating sections. Heat sources 6700 may be placed within first section8600. Heat sources 6700 may be placed in a desired pattern, (e.g.,hexagonal, triangular, square, etc.). In an embodiment, heat sources6700 are placed in triangular patterns as shown in FIG. 137. A spacingbetween heat sources 6700 may be less than about 25 m within firstsection 8600 or, in some embodiments, less about 20 m or less than about15 m. A volume of first section 8600 (as well as second sections 8602and third sections 8604) may be determined by a pattern and spacing ofheat sources 6700 within the section and/or a heat output of the heatsources. Production wells 6710 may be placed within first section 8600.A number, orientation, and/or location of production wells 6710 may bedetermined by considerations including, but not limited to, a desiredproduction rate, a selected product quality, and/or a ratio of heavyhydrocarbons to light hydrocarbons. For example, one production well6710 may be placed in an upper portion of first section 8600 as shown inFIG. 137. In some embodiments, an injection well 6711 is placed in firstsection 8600. Injection well 6711 (and/or a heat source or productionwell) may be used to provide a pressurizing fluid into first section8600. The pressurizing fluid may include, but is not limited to, steam,carbon dioxide, N₂, CH₄, combustion products, non-condensable andcondensable fluid produced from the formation, or combinations thereof.In certain embodiments, a location of injection well 6711 is chosen suchthat the recovery of fluids from first section 8600 is increased withthe provided pressurizing fluid.

[1401] In an embodiment, heat sources 6700 are used to provide heat tofirst section 8600. First section 8600 may be heated such that at leastsome heavy hydrocarbons within the first section are mobilized. Atemperature at which at least some hydrocarbons are mobilized (i.e., amobilization temperature) may be between about 50° C. and about 210° C.In other embodiments, a mobilization temperature is between about 50° C.and about 150° C. or between about 50° C. and about 100° C.

[1402] In an embodiment, a first mixture is produced from first section8600. The first mixture may be produced through production well 6710 orproduction wells and/or heat sources 6700. The first mixture may includemobilized fluids from the first section. The mobilized fluids mayinclude at least some hydrocarbons from first section 8600. In certainembodiments, the mobilized fluids produced include heavy hydrocarbons.An API gravity of the first mixture may be less than about 20°, lessthan about 15°, or less than about 10°. In some embodiments, the firstmixture includes at least some pyrolyzed hydrocarbons. Some hydrocarbonsmay be pyrolyzed in portions of first section 8600 that are at highertemperatures than a remainder of the first section. For example,portions adjacent heat sources 6700 may be at somewhat highertemperatures (e.g., approximately 50° C. to approximately 100° C.higher) than the remainder of first section 8600.

[1403] As shown in FIG. 137, second sections 8602 may be adjacent tofirst section 8600. Second section 8602 may include heat sources 6700.Heat sources 6700 in second section 8602 may be arranged in a patternsimilar to a pattern of heat sources 6700 in first section 8600. In someembodiments, heat sources 6700 in second section 8602 are arranged in adifferent pattern than heat sources 6700 in first section 8600 toprovide desired heating of the second section. In certain embodiments, aspacing between heat sources 6700 in second section 8602 is greater thana spacing between heat sources 6700 in first section 8600. Heat sources6700 may provide heat to second section 8602 to mobilize at least somehydrocarbons within the second section.

[1404] In an embodiment, temperature within first section 8600 may beincreased to a pyrolyzation temperature after production of the firstmixture. A pyrolyzation temperature in the first section may be betweenabout 225° C. and about 375° C. In some instances, a pyrolyzationtemperature in the first section may be at least about 250° C., or atleast about 275° C. Mobilized fluids (e.g., mobilized heavyhydrocarbons) from second section 8602 may be allowed to flow into firstsection 8600. Some of the mobilized fluids from second section 8602 thatflow into first section 8600 may be pyrolyzed within the first section.Pyrolyzing the mobilized fluids in first section 8600 may upgrade aquality of fluids (e.g., increase an API gravity of the fluid).

[1405] In certain embodiments, a second mixture is produced from firstsection 8600. The second mixture may be produced through production well6710 or production wells and/or heat sources 6700. The second mixturemay include at least some hydrocarbons pyrolyzed within first section8600. Mobilized fluids from second section 8602 and/or hydrocarbonsoriginally within first section 8600 may be pyrolyzed within the firstsection. Conversion of heavy hydrocarbons to light hydrocarbons bypyrolysis may be controlled by controlling heat provided to firstsection 8600 and second section 8602. In some embodiments, the heatprovided to first section 8600 and second section 8602 is controlled byadjusting the heat output of a heat source or heat sources 6700 withinthe first section. In other embodiments, the heat provided to firstsection 8600 and second section 8602 is controlled by adjusting the heatoutput of a heat source or heat sources 6700 within the second section.The heat output of heat sources 6700 within first section 8600 andsecond section 8602 may be adjusted to control the heat distributionwithin hydrocarbon layer 6704 to account for the flow of fluids along avertical and/or horizontal plane within the formation. For example, theheat output may be adjusted to balance heat and mass fluxes within theformation so that mass within the formation (e.g., fluids within theformation) is substantially uniformly heated.

[1406] Producing fluid from production wells in the first section maylower the average pressure in the formation by forming an expansionvolume for fluids heated in adjacent sections of the formation. Thus,producing fluid from production wells in the first section may establisha pressure gradient in the formation that draws mobilized fluid fromadjacent sections into the first section. In some embodiments, apressurizing fluid is provided in second section 8602 (e.g., throughinjection well 6711) to increase mobilization of hydrocarbons within thesecond section. The pressurizing fluid may enhance the pressure gradientin the formation to flow mobilized hydrocarbons into first section 8600.In certain embodiments, the production of fluids from first section 8600allows the pressure in second section 8602 to remain below a selectedpressure (e.g., a pressure below which fracturing of the overburden mayoccur).

[1407] In some embodiments, a pressurizing fluid is provided into secondsection 8602 (e.g., through injection well 6711) to increasemobilization of hydrocarbons within the second section. The pressurizingfluid may also be used to increase a flow of mobilized hydrocarbons intofirst section 8600. For example, a pressure gradient may be producedbetween second section 8602 and first section 8600 such that the flow offluids from the second section to the first section is increased.

[1408] As shown in FIG. 137, third section 8604 may be adjacent tosecond section 8602. Heat may be provided to third section 8604 fromheat sources 6700. Heat sources 6700 in third section 8604 may bearranged in a pattern similar to a pattern of heat sources 6700 in firstsection 8600 and/or heat sources in the second section 8602. In someembodiments, heat sources 6700 in third section 8604 are arranged in adifferent pattern than heat sources 6700 in first section 8600 and/orheat sources in the second section 8602. In certain embodiments, aspacing between heat sources 6700 in third section 8604 is greater thana spacing between heat sources 6700 in first section 8600. Heat sources6700 may provide heat to third section 8604 to mobilize at least somehydrocarbons within the third section.

[1409] In an embodiment, a temperature within second section 8602 may beincreased to a pyrolyzation temperature after production of the firstmixture. Mobilized fluids from third section 8604 may be allowed to flowinto second section 8602. Some of the mobilized fluids from thirdsection 8604 that flow into second section 8602 may be pyrolyzed withinthe second section. A mixture may be produced from second section 8602.The mixture produced from second section 8602 may include at least somepyrolyzed hydrocarbons. An API gravity of the mixture produced fromsecond section 8602 may be at least about 20°, 30°, or 40°. The mixturemay be produced through production wells 6710 and/or heat sources 6700placed in second section 8602. Heat provided to third section 8604 andsecond section 8602 may be controlled to control conversion of heavyhydrocarbons to light hydrocarbons and/or a desired characteristic ofthe mixture produced in the second section.

[1410] In another embodiment, mobilized fluids from third section 8604are allowed to flow through second section 8602 and into first section8600. At least some of the mobilized fluids from third section 8604 maybe pyrolyzed in first section 8600. In addition, some of the mobilizedfluids from third section 8604 may be produced as a portion of thesecond mixture in first section 8600. The heavy hydrocarbon fraction inproduced fluids may decrease as successive sections of the formation areproduced through first section 8600.

[1411] In some embodiments, a pressurizing fluid is provided in thirdsection 8604 (e.g., through injection well 6711) to increasemobilization of hydrocarbons within the third section. The pressurizingfluid may also be used to increase a flow of mobilized hydrocarbons intosecond section 8602 and/or first section 8600. For example, a pressuregradient may be produced between third section 8604 and first section8600 such that the flow of fluids from the third section towards thefirst section is increased.

[1412] In an embodiment, heat provided to second section 8602, thirdsection 8604, and any subsequent sections may be turned onsimultaneously after first section 8600 has been substantially depletedof hydrocarbons and other fluids (e.g., brine). The delay betweenturning on first section 8600 and subsequent sections (e.g., secondsection 8602, third section 8604, etc.) may be, for example, about 1year, about 1.5 years, or about 2 years.

[1413] Hydrocarbons may be produced from first section 8600 and/orsecond section 8602 such that at least about 50% by weight of theinitial mass of hydrocarbons in the formation are produced. In otherembodiments, at least about 60% by weight or at least about 70% byweight of the initial mass of hydrocarbons in the formation areproduced.

[1414] In certain embodiments, hydrocarbons may be produced from theformation such that at least about 60% by volume of the initial volumein place of hydrocarbons is produced from the formation. In someembodiments, at least about 70% by volume of the initial volume in placeof hydrocarbons or at least about 80% by volume of the initial volume inplace of hydrocarbons may be produced from the formation.

[1415]FIG. 138 depicts a schematic of an embodiment for treating arelatively permeable formation using a combination of production andheater wells in the formation. Heat sources 6700 and 6702 may be placedsubstantially horizontally within hydrocarbon layer 6704. Heat sources6700 may be placed in upper portion 6706 of hydrocarbon layer 6704. Heatsources 6702 may be placed in lower portion 6708 of hydrocarbon layer6704. In some embodiments, heat sources 6700, 6702 or selected heatsources may be used as fluid injection wells. Heat sources 6700 and/orheat sources 6702 may be placed in a triangular pattern withinhydrocarbon layer 6704. A pattern of heat sources within hydrocarbonlayer 6704 may be repeated as needed depending on various factors (e.g.,a width of the formation, a desired heating rate, and/or a desiredproduction rate).

[1416] Other patterns of heat sources, such as squares, rectangles,hexagons, octagons, etc., may be used within the formation. In someembodiments, heat sources 6702 may be placed proximate a bottom ofhydrocarbon layer 6704. Heat sources 6702 may be placed from about 1 mto about 6 m from the bottom of the formation, from about 1 m to about 4m from the bottom of the formation, or possibly from about 1 m to about2 m from the bottom of the formation. In certain embodiments, heat inputvaries between heat sources 6700 and heat sources 6702. The differencein heat input may reduce costs and/or allow for production of a desiredproduct. For example, heat sources 6700 in an upper portion of theformation may be turned down and/or off after some fluids withinhydrocarbon layer 6704 have been mobilized. Turning off or reducing heatoutput of a heater may inhibit excessive cracking of hydrocarbon vaporsbefore the vapors are produced from the formation. Turning off orreducing heat output of a heater or heaters may reduce energy costs forheating the formation.

[1417]FIG. 139 depicts a schematic of the embodiment of FIG. 138. Heatsources 6700 and 6702 may be placed substantially horizontally withinhydrocarbon layer 6704. Heat sources 6700 and 6702 may enter hydrocarbonlayer 6704 through one or more vertical or slanted wellbores formedthrough an overburden of the formation. In some embodiments, each heatsource may have its own wellbore. In other embodiments, one or more heatsources may branch from a common wellbore. In another embodiment, one ormore heat sources are placed in the formation as shown in FIGS. 6 and 7.

[1418] Formation fluids may be produced through production wells 6710,as shown in FIGS. 138 and 139. In certain embodiments, production wells6710 are placed in upper portion 6706 of hydrocarbon layer 6704.Production well 6710 may be placed proximate overburden 540. Forexample, production well 6710 may be placed about 1 m to about 20 m fromoverburden 540, about 1 m to about 4 m from the overburden, or possiblyabout 1 m to about 3 m from the overburden. In some embodiments, atleast some formation fluids are produced through heat sources 6700, 6702or selected heat sources.

[1419] In some embodiments, a pressurizing fluid (e.g., a gas) isprovided to a relatively permeable formation to increase mobility ofhydrocarbons within the formation. Providing a pressurizing fluid mayincrease a shear rate applied to hydrocarbon fluids in the formation anddecrease the viscosity of hydrocarbon fluids within the formation. Insome embodiments, pressurizing fluid is provided to the selected sectionbefore significant heating of the formation. Pressurizing fluidinjection may increase a portion of the formation available forproduction. Pressurizing fluid injection may increase a ratio of energyoutput of the formation (i.e., energy content of products produced fromthe formation) to energy input into the formation (i.e., energy costsfor treating the formation).

[1420] As shown in FIG. 138, injection wells 6711 may be placed in theformation to introduce the pressurizing fluid into the formation.Injection wells 6711 may, in certain embodiments, be placed between twoheat sources 6700, 6702. However, a location of an injection well may bevaried. In certain embodiments, a pressurizing fluid is injected througha heat source or production well placed in a relatively permeableformation. In some embodiments, more than one injection well 6711 isplaced in the formation. The pressurizing fluid may include gases suchas carbon dioxide, N₂, steam, CH₄, and/or mixtures thereof. In someembodiments, fluids produced from the formation (e.g., combustion gases,heater exhaust gases, or produced formation fluids) may be used aspressurizing fluid. Providing the pressurizing fluid may increase apressure in a selected section of the formation. The pressure in theselected section may be maintained below a selected pressure. Forexample, the pressure may be maintained below about 150 bars absolute,about 100 bars absolute, or about 50 bars absolute. In some embodiments,the pressure may be maintained below about 35 bars absolute. Pressuremay be varied depending on a number of factors (e.g., desired productionrate or an initial viscosity of tar in the formation). Injection of agas into the formation may result in a viscosity reduction of some ofthe tar in the formation.

[1421] In some embodiments, pressure is maintained by controlling flow(e.g., injection rate) of the pressurizing fluid into the selectedsection. In other embodiments, the pressure is controlled by varying alocation for injecting the pressurizing fluid. In other embodiments,pressure is maintained by controlling a pressure and/or production rateat production wells 6710.

[1422] In certain embodiments, heat sources may be used to generate apath for a flow of fluids between an injection well and a productionwell. The viscosity of heavy hydrocarbons at or near a heat source isreduced by the heat provided from the heat source. The reduced viscosityhydrocarbons may be immobile until a path is created for flow of thehydrocarbons. The path for flow of the hydrocarbons may be created byplacing an injection well and a production well at different positionsalong the length of the heat source and proximate the heat source. Apressurizing fluid provided through the injection well may produce aflow of the reduced viscosity hydrocarbons towards the production well.

[1423]FIG. 140 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation. Heat source 6700 may be placedsubstantially horizontally within opening 514 in hydrocarbon layer 6704.The substantially horizontal portion of opening 514 may be placed in alower portion of hydrocarbon layer 6704 and/or proximate the bottom ofthe hydrocarbon layer. Opening 514 may, in certain embodiments, be casedwith perforations 8612 located proximate the heel of heat source 6700.Injection wells 6711 may be placed substantially vertically inhydrocarbon layer 6704. At least one injection well 6711 may be placednear the toe of heat source 6700. Another injection well 6711 may beplaced proximate the midline of the horizontal section of heat source6700. More or less injection wells 6711 may be used depending on, forexample, the size of hydrocarbon layer 6704, a desired production rate,etc.

[1424] Heat source 6700 may provide heat to hydrocarbon layer 6704 toreduce the viscosity of hydrocarbons in the formation. The viscosity ofhydrocarbons at or near heat source 6700 decreases earlier thanhydrocarbons further away from the heat sources because of the radialpropagation of heat fronts away from the heat sources. A pressurizingfluid (e.g., steam) may be provided into the formation through injectionwells 6711. The pressurizing fluid may produce a flow of the reducedviscosity hydrocarbons towards perforations 8612. Hydrocarbons and/orother fluids may be produced through perforations 8612 and from theformation along a length of opening 514. The produced fluids may befurther heated along the length of opening 514 by heat source 6700 tomaintain produced fluids in a vapor phase and/or further crack producedfluids along the length of the heat source. The flow of fluids inhydrocarbon layer 6704 are represented by the arrows in FIG. 140. Theflow may be controlled by an injection rate of the pressurizing fluidand/or a pressure in opening 514.

[1425]FIG. 141 depicts a schematic of another embodiment for injecting apressurizing fluid into hydrocarbon layer 6704. As shown in FIG. 141,injection well 6711 may be placed substantially horizontally inhydrocarbon layer 6704. Injection well 6711 may also be placed proximatethe top of hydrocarbon layer 6704 and/or in an upper portion of thehydrocarbon layer. Heat source 6700 may be placed substantiallyhorizontally within opening 514 in hydrocarbon layer 6704. Thesubstantially horizontal portion of opening 514 may be placed in a lowerportion of hydrocarbon layer 6704 and/or proximate the bottom of thehydrocarbon layer. Opening 514 may, in certain embodiments, be a casedopening with perforations 8612 placed proximate the toe of heat source6700. The flow of reduced viscosity hydrocarbons produced by injectionof a pressurizing fluid (e.g., steam) may be along the length of heatsource 6700 between an end of injection well 6711 proximate opening 514and towards perforations 8612 as represented by the arrows in FIG. 141.Mobilized fluids (e.g., hydrocarbons, pressurizing fluid, etc.) may beproduced through perforations 8612. The produced fluids may be furtherheated along the length of opening 514 by heat source 6700 to maintainproduced fluids in a vapor phase and/or further crack produced fluidsalong the length of the heat source.

[1426]FIG. 142 depicts a schematic of an alternate embodiment forinjecting a pressurizing fluid into hydrocarbon layer 6704. Injectionwell 6711 may be placed substantially horizontally within hydrocarbonlayer 6704. Injection well 6711 may also be placed proximate the top ofhydrocarbon layer 6704 and/or in an upper portion of the hydrocarbonlayer. Heat sources 6700 may be placed within opening 514 in hydrocarbonlayer 6704. Heat sources 6700 may have toe portions that proximatelymeet, but do not necessarily touch, near a midsection of thesubstantially horizontal portion of opening 514. The substantiallyhorizontal portion of opening 514 may be placed in a lower portion ofhydrocarbon layer 6704 and/or proximate the bottom of the hydrocarbonlayer. Perforations 8612 may be placed at or near the heel of one heatsource 6700. The flow of reduced viscosity hydrocarbons produced byinjection of a pressurizing fluid (e.g., steam) through injection well6711 may be from proximate a top portion of one heat source 6700 andalong a length of opening 514 towards perforations 8612 as shown by thearrows in FIG. 142. Mobilized fluids (e.g., hydrocarbons, pressurizingfluid, etc.) may be produced through perforations 8612. The producedfluids may be further heated along the length of opening 514 by heatsource 6700 to maintain produced fluids in a vapor phase and/or furthercrack produced fluids along the length of the heat source.

[1427]FIG. 143 depicts a schematic of an alternate embodiment forinjecting a pressurizing fluid into hydrocarbon layer 6704. As shown bythe arrows in FIG. 143, fluids may be produced from an end of opening514 opposite of an end in which the fluids are produced in theembodiment of FIG. 142. Producing the fluids as shown in FIG. 143 mayincrease the time that produced fluids are exposed to heat from heatsources 6700. Increasing the heating of the produced fluids may increasecracking and/or upgrading of the produced fluids.

[1428]FIG. 144 depicts a schematic of another embodiment for injecting apressurizing fluid into hydrocarbon layer 6704. Injection well 6711 maybe placed substantially vertically in hydrocarbon layer 6704. Productionwell 6710 may be placed substantially vertically in hydrocarbon layer6704. In some embodiments, production well 6710 may be heated tomaintain produced fluids in a vapor phase and/or further crack producedfluids along the length of the production well.

[1429] As shown in FIG. 144, heat source 6700 may be placedsubstantially horizontally within opening 514 in hydrocarbon layer 6704.The substantially horizontal portion of opening 514 may be placed in alower portion of hydrocarbon layer 6704 and/or proximate the bottom ofthe hydrocarbon layer. Opening 514 may, in certain embodiments, be acased opening. The flow of reduced viscosity hydrocarbons produced byinjection of a pressurizing fluid (e.g., steam) may be along the lengthof heat source 6700 between an end of injection well 6711 proximate theheel of the heat source and towards an end of production well 6710proximate the toe of the heat source as represented by the arrows inFIG. 144. Mobilized fluids (e.g., hydrocarbons, pressurizing fluid,etc.) may be produced through perforations 8612 in production well 6710.

[1430] In an embodiment, after a flow of hydrocarbons has been createdin hydrocarbon layer 6704, heat sources 6700 may be turned down and/oroff. Turning down and/or off heat sources 6700 may save on energy costsfor producing fluids from the formation. Fluids may continue to beproduced from hydrocarbon layer 6704 using injection of pressurizingfluid to mobilize and sweep fluids towards perforations 8612 and/orproduction well 6710. In certain embodiments, the pressurizing fluid maybe heated to elevated temperatures at the surface (e.g., in a heatexchanger). The heated pressurizing fluid may be used to provide someheat to hydrocarbon layer 6704. In an embodiment, heated pressurizingfluid may be used to maintain a temperature in the formation afterreducing and/or turning off heat provided by heat sources 6700.

[1431] Providing the pressurizing fluid in the selected section mayincrease sweeping of hydrocarbons from the formation (i.e., increase thetotal amount of hydrocarbons heated and produced in the formation).Increased sweeping of hydrocarbons in the formation may increase totalhydrocarbon recovery from the formation. In some embodiments, greaterthan about 50% by weight of the initial estimated mass of hydrocarbonsmay be produced from the formation. In other embodiments, greater thanabout 60% by weight or greater than about 70% by weight of the initialestimated mass of hydrocarbons may be produced from the formation.

[1432] In an embodiment, greater than about 60% by volume of the initialvolume in place of hydrocarbons in the formation are produced aformation. In other embodiments, greater than about 70% by volume orgreater than about 80% by volume of the initial volume in place ofhydrocarbons may be produced from a formation.

[1433] In an embodiment, a portion of a relatively permeable formationmay be heated to increase a partial pressure of H₂. The partial pressureof H₂ may be measured at a production well, a monitoring well, a heaterwell and/or an injection well. In some embodiments, an increased H₂partial pressure may include H₂ partial pressures in a range from about0.5 bars absolute to about 7 bars absolute. Alternatively, an increasedH₂ partial pressure range may include H₂ partial pressures in a rangefrom about 5 bars absolute to about 7 bars absolute. For example, amajority of hydrocarbon fluids may be produced wherein a H₂ partialpressure is within a range of about 5 bars absolute to about 7 barsabsolute. A range of H₂ partial pressures within the pyrolysis H₂partial pressure range may vary depending on, for example, temperatureand pressure of the heated portion of the formation.

[1434] In an embodiment, pressure within a formation may be controlledto enhance production of hydrocarbons of a desired carbon numberdistribution. Low formation pressure may favor production ofhydrocarbons having a high carbon number distribution (e.g., condensablehydrocarbons). Low pressure in the formation may reduce the cracking ofhydrocarbons into lighter hydrocarbons. Thus, reducing pressure in theformation may increase the production of condensable hydrocarbons andlower the production of non-condensable hydrocarbons. Operating at lowerpressure in the formation may inhibit the production of carbon dioxidein the formation and/or increase the recovery of hydrocarbons from theformation.

[1435] Pressure within a relatively permeable formation may becontrolled and/or reduced by creating a pressure sink within theformation. In an embodiment, a first section of the formation may beheated prior to other sections (i.e., adjacent sections) of theformation. At least some hydrocarbons within the first section may bepyrolyzed during heating of the first section. Pyrolyzed hydrocarbons(e.g., light hydrocarbons) from the first section may be produced beforeor during start-up of heating in other sections (i.e., during earlytimes of heating before temperatures within the other sections reachpyrolysis temperatures). In some embodiments, some un-pyrolyzedhydrocarbons (e.g., heavy hydrocarbons) may be produced from the firstsection. The un-pyrolyzed hydrocarbons may be produced during earlytimes of heating when temperatures within the first section are belowpyrolysis temperatures. Producing fluid from the first section mayestablish a pressure gradient in the formation with the lowest pressurelocated at the production wells.

[1436] When a section of formation adjacent to the first section isheated, heat applied to the formation may mobilize the hydrocarbons.Mobilized liquid hydrocarbons may move downwards by gravity drainage.Mobilized vapor hydrocarbons may move towards the first section due to apressure gradient caused by production of fluids from the first section.Movement of mobilized vapor hydrocarbons towards the first section mayinhibit excess pressure buildup in the sections being heated and/orpyrolyzed. Temperature of the first section may be maintained above acondensation temperature of desired hydrocarbon fluids that are to beproduced from the production wells in the first section.

[1437] Producing fluids from other sections through production wells inthe first section may reduce the number of production wells needed toproduce fluids from a formation. Pressure in the other sections (e.g.,pressures at and adjacent to heat sources in the other sections) of theformation may remain low. Low formation pressure may be maintained evenin relatively deep relatively permeable formations. For example, aformation pressure may be maintained below about 15 bars absolute in aformation that is about 540 m below the surface.

[1438] Controlling the pressure in the sections being heated may inhibitcasing collapse in the heat sources. Controlling the pressure in thesections being heated may inhibit excessive coke formation on andadjacent to the heat sources. Pressure in the sections being heated maybe controlled by controlling production rate of fluid from productionwells in adjacent sections and/or by releasing pressure at or adjacentto heat sources in the section being heated.

[1439]FIG. 145 depicts a cross-sectional representation of an embodimentfor treating a relatively permeable formation. Heat sources 6700 may beused to provide heat to sections 9250, 9252, 9254 of hydrocarbon layer6704. Heat sources 6700 may be placed in a similar pattern as shown inthe embodiment of FIG. 137. Production well 6710 may be placed a centerof first section 9250. Production well 6710 may be placed substantiallyhorizontally within first section 9250. Other locations and/ororientations for production well 6710 may be used depending on, forexample, a desired production rate, a desired product quality orcharacteristic, etc.

[1440] In an embodiment, heat may be provided to first section 9250 fromheat sources 6700. Heat provided to first section 9250 may mobilize atleast some hydrocarbons within the first section. Hydrocarbons withinfirst section 9250 may be mobilized at temperatures above about 50° C.or, in some embodiments, above about 75° C. or above about 100° C. In anembodiment, production of mobilized hydrocarbons may be inhibited untilpyrolysis temperatures are reached in first section 9250. Inhibiting theproduction of hydrocarbons while increasing temperature within firstsection 9250 tends to increase the pressure within the first section. Insome embodiments, at least some mobilized hydrocarbons may be producedthrough production well 6710 to inhibit excessive pressure buildup inthe formation. The produced mobilized hydrocarbons may include heavyhydrocarbons, liquid-phase light hydrocarbons, and/or un-pyrolyzedhydrocarbons. In certain embodiments, only a portion of the mobilizedhydrocarbons is produced, such that the pressure in first section 9250is maintained below a selected pressure. The selected pressure may be,for example, a lithostatic pressure, a hydrostatic pressure, or apressure selected to produce a desired product characteristic.

[1441] In an embodiment, heat may be provided to first section 9250 fromheat sources 6700 to increase temperatures within the first section topyrolysis temperatures. Pyrolysis temperatures may include temperaturesabove about 250° C. In some embodiments, pyrolysis temperatures may beabove about 270° C., 300° C., or 325° C. Pyrolyzed hydrocarbons fromfirst section 9250 may be produced through production well 6710 orproduction wells. During production of hydrocarbons through productionwell 6710 or production wells, heat may be provided to second sections9252 from heat sources 6700 to mobilize hydrocarbons within the secondsection. Further heating of second sections 9252 may pyrolyze at leastsome hydrocarbons within the second section. Heat may also be providedto third sections 9254 from heat sources 6700 to mobilize and/orpyrolyze hydrocarbons within the third section. In some embodiments,heat sources 6700 in third sections 9254 may be turned on after heatsources 6700 in second sections 9252. In other embodiments, heat sources6700 in third sections 9254 are turned on simultaneously with heatsources 6700 in second sections 9252.

[1442] Producing hydrocarbons from first section 9250 at production well6710 or production wells may create a pressure sink at the productionwell. The pressure sink may be a low pressure zone around productionwell 6710 or production wells as compared to the pressure in theformation. Fluids from second sections 9252 and third sections 9254 mayflow towards production well 6710 or production wells because of thepressure sink at the production well. The fluids that flow towardsproduction well 6710 may include at least some vapor phase lighthydrocarbons. In some embodiments, the fluids may include some liquidphase hydrocarbons. The flow of fluids towards production well 6710 maymaintain lower pressures in second sections 9252 and third sections 9254than if the fluids remain within these sections and are heated to highertemperatures. In addition, fluids that flow towards production well 6710may have a shorter residence time in the heated sections and undergoless pyrolyzation than fluids that remain within the heated sections. Atleast a portion of fluids from second sections 9252 and/or thirdsections 9254 may be produced through production well 6710. In certainembodiments, one or more production wells may be placed in secondsections 9252 and/or third sections 9254 to produce at least somehydrocarbons from these sections.

[1443] After substantial production of the hydrocarbons that areinitially present in each of the sections (first section 9250, secondsections 9252, and third sections 9254), heat sources 6700 in each ofthe sections may be turned down and/or off to reduce the heat providedto the section. Turning down and/or off heat sources 6700 may reduceenergy input costs for heating the formation. In addition, turning downand/or off heat sources 6700 may inhibit further cracking ofhydrocarbons as the hydrocarbons flow towards production well 6710and/or other production wells in the formation. In an embodiment, heatsources 6700 in first section 9250 are turned off before heat sources6700 in second sections 9252 or heat sources 6700 in third sections9254. The time and duration each heat source 6700 in each section 9250,9252, 9254 is turned on may be determined based on experimental and/orsimulation data.

[1444] The flow of fluids towards production well 6710 may increase therecovery of hydrocarbons from the formation. Generally, decreasing thepressure in the formation tends to increase the cumulative recovery ofhydrocarbons from the formation and decrease the production ofnon-condensable hydrocarbons from the formation. Decreasing theproduction of non-condensable hydrocarbons may result in a decrease inthe API gravity of a mixture produced from the formation. In someembodiments, a pressure may be selected to balance a desired API gravityin the produced mixture with a recovery of hydrocarbons from theformation. The flow of fluids towards production well 6710 may increasea sweep efficiency of hydrocarbons from the formation. Increased sweepefficiency may result in increased recovery of hydrocarbons from theformation.

[1445] In certain embodiments, pressure within the formation may beselected to produce a mixture from the formation with a desired quality.Pressure within the formation may be controlled by, for example,controlling heating rates within the formation, controlling theproduction rate through production well 6710 or production wells,controlling the time for turning on heat sources 6700, controlling theduration for using heat sources 6700, etc. Pressures within theformation along with other operating conditions (e.g., temperature,production rate, etc.) may be selected and controlled to produce amixture with desired qualities. In certain embodiments, pressure and/orother operating conditions in the formation may be selected based on aprice characteristic of the produced mixture.

[1446] In some embodiments, one or more injection wells may be placed inthe formation. The one or more injection wells may be used to inject apressurizing fluid into the formation. Injecting a pressurizing fluidinto the formation may be used to increase the recovery of hydrocarbonsfrom the formation and/or to increase a pressure in the formation.Controlling the flow rate of pressurizing fluid may control pressure inthe formation.

[1447] In certain embodiments, a substantial portion of hydrocarbonsfrom a formation may be recovered (i.e., produced) in a single pass insitu recovery process. A single pass in situ recovery process mayinclude staged heating of the formation and/or a single step ofinjection fluid into the formation. Typically, multiple pass processes(e.g., secondary or tertiary pass processes) include multiple steps ofinjecting liquids or gases into a formation to promote recovery from theformation. For example, steam flood recovery from a tar sands formationmay include more than one step of injecting steam into the formationand/or recycling of fluids (e.g., steam or product fluids) back into theformation for further recovery. The recovery efficiency for hydrocarbonsin a single pass in situ recovery process may be improved compared tothe recovery efficiency of multiple fluid injection step processes. Inaddition, a single pass in situ recovery process may produce arelatively flat production rate through the process. The relatively flatproduction rate may reduce or minimize surface facility requirementsneeded for treatment of product fluids. Typically, large surfacefacilities are required in multiple step processes for the large initialproduction of fluid, while during subsequent production steps theproduction rate steeply decreases resulting in unused surface facilitycapacity.

[1448] Producing formation fluids in the upper portion of the formationmay allow for production of hydrocarbons substantially in a vapor phase.Lighter hydrocarbons may be produced from production wells placed in theupper portion of the relatively permeable formation. Hydrocarbonsproduced from an upper portion of the formation may be upgraded ascompared to hydrocarbons produced from a lower portion of the formation.Producing through wells in the upper portion may also inhibit coking ofproduced fluids at the production wellbore. Producing through wellsplaced in a lower portion of the formation may produce a heavierhydrocarbon fluid than is produced in the upper portion of theformation. The heavier hydrocarbon fluid may contain substantial amountsof cold bitumen or tar. Cold bitumen or tar production tends to bedecreased when producing through wells placed in the upper portion ofthe formation. In some embodiments, the upper portion of the formationmay include an upper half of the formation. However, a size of the upperportion may vary depending on several factors (e.g., a thickness of theformation, vertical permeability of the formation, a desired quality ofproduced fluid, or a desired production rate).

[1449] In some embodiments, a quality of a mixture produced from aformation is controlled by varying a location for producing the mixturewithin the formation. The quality of the mixture produced may be ratedon variety of factors (e.g., API gravity of the mixture, carbon numberdistribution, a weight ratio of components in the mixture, and/or apartial pressure of hydrogen in the mixture). Other qualities of themixture may include, but are not limited to, a ratio of heavyhydrocarbons to light hydrocarbons in the mixture and/or a ratio ofaromatics to paraffins in the mixture. In one embodiment, the locationfor producing the mixture is varied by varying a location of aproduction well within the formation. For example, the quality of themixture can be varied by varying a distance between a production welland a heat source. Locating the production well closer to the heatsource may increase cracking at or near the production well, thus,increasing, for example, an API gravity of the mixture produced. In someembodiments, a number of production wells in a portion of the formationor a production rate from a portion of the formation may be used tocontrol the quality of a mixture produced

[1450] In some embodiments, varying a location for production includesvarying a portion of the formation from which the mixture is produced.For example, a mixture may be produced from an upper portion of theformation, a middle portion of the formation, and/or a lower portion ofthe formation at various times during production from a formation.Varying the portion of the formation from which the mixture is producedmay include varying a depth of a production well within the formationand/or varying a depth for producing the mixture within a productionwell. In certain embodiments, the quality of the produced mixture isincreased by producing in an upper portion of the formation rather thana middle or lower portion of the formation. Producing in the upperportion tends to increase the amount of vapor phase and/or lighthydrocarbon production from the formation. Producing in lower portionsof the formation may decrease a quality of the produced mixture;however, a total mass recovery from the formation and/or a portion ofthe formation selected for treatment (i.e., a weight percentage ofinitial mass of hydrocarbons in the formation, or in the selectedportion, produced) can be increased by producing in lower portions(e.g., the middle portion or lower portion of the formation). Producingin the lower portion may, in some embodiments, provide the highest totalmass recovery, energy recovery, and/or a better energy balance.

[1451] In certain embodiments, an upper portion of the formationincludes about one-third of the formation closest to an overburden ofthe formation. The upper portion of the formation, however, may includeup to about 35%, 40%, or 45% of the formation closest to the overburden.A lower portion of the formation may include a percentage of theformation closest to an underburden, or base rock, of the formation thatis substantially equivalent to the percentage of the formation that isincluded in the upper portion. A middle portion of the formation mayinclude the remainder of the formation between the upper portion and thelower portion. For example, the upper portion may include aboutone-third of the formation closest to the overburden while the lowerportion includes about one-third of the formation closest to theunderburden and the middle portion includes the remaining third of theformation between the upper portion and the lower portion. FIG. 146(described below) depicts embodiments of upper portion 8620, middleportion 8622, and lower portion 8624 in hydrocarbon layer 6704 alongwith production well 6710.

[1452] In some embodiments, the lower portion includes a differentpercentage of the formation than the upper portion. For example, theupper portion may include about 30% of the formation closest to theoverburden while the lower portion includes about 40% of the formationclosest to the underburden and the middle portion includes the remaining30% of the formation. Percentages of the formation included in theupper, middle, and lower portions of the formation may vary dependingon, for example, placement of heat sources in the formation, spacing ofheat sources in the formation, a structure of the formation (e.g.,impermeable layers within the formation), etc. In some embodiments, aformation may include only an upper portion and a lower portion. Inaddition, the percentages of the formation included in the upper,middle, and lower portions of the formation may vary due to variation ofpermeability within the formation. In some formations, permeability mayvary vertically within the formation. For example, the permeability inthe formation may be lower in an upper portion of the formation than alower portion of the formation.

[1453] In some cases, the upper, middle, and lower portions of arelatively permeable formation may be determined by characteristics ofthe portions. For example, a middle portion may include a portion thatis high enough within the formation to not allow heavy hydrocarbons tosettle in the portion after at least some hydrocarbons have beenmobilized. A bottom portion may be a portion where the heavyhydrocarbons are substantially settled after mobilization due to gravitydrainage. A top portion may be a portion where production issubstantially vapor phase production after mobilization of at least someheavy hydrocarbons.

[1454] In an embodiment, selecting the location for producing a mixturefrom a formation includes selecting the location based on a pricecharacteristic for the produced mixture. The price characteristic may bea price characteristic of hydrocarbons produced from the formation. Theprice characteristic may be determined by multiplying a production rateof the produce mixture at a selected API gravity by a price obtainablefor selling the produced mixture with the selected API gravity. In someembodiments, the price characteristic may be determined as a function ofthe API gravity of the produced mixture, the total mass recovery fromthe formation, a price obtainable for selling the produced mixture,and/or other factors affecting production of the mixture from theformation. Other characteristics, however, may also be included in theprice characteristic. For example, other characteristics may include,but are not limited to, a selling price of hydrocarbon components in theproduced mixture, a selling price of sulfur produced, a selling price ofmetals produced, a ratio of paraffins to aromatics produced, and/or aweight percentage of heavy hydrocarbons in the mixture.

[1455] In some instances, the price characteristic may change duringproduction of the mixture from the formation. The price characteristicmay change, for example, based on a change in the selling price of theproduced mixture or of a hydrocarbon component in the mixture. In such acase, a parameter for producing the mixture may be adjusted based on thechange in the price characteristic. In an embodiment, the parameter forproducing the mixture is a location for producing the mixture within theformation.

[1456] In some embodiments, the parameter may include operatingconditions within the formation that are controlled based on the pricecharacteristic. Operating conditions may include parameters such as, butnot limited to, pressure, temperature, heating rate, and heat outputfrom one or more heat sources. Operating conditions within the formationmay be adjusted based on a change in the price characteristic duringproduction of the mixture from the formation.

[1457] In certain embodiments, the price characteristic may be based ona relationship between cumulative oil (hydrocarbon) recovery and APIgravity. Generally, increasing the API gravity produced from a formationby an in situ conversion process tends to decrease the cumulativehydrocarbon recovery from the formation (i.e., total mass recovery). Inan embodiment, the relationship between API gravity of the producedhydrocarbons and total mass recovery is a linear relationship. Thelinear relationship may be based on, for example, experimental data(e.g., pyrolysis data) and/or simulation data (e.g., STARS simulationdata).

[1458]FIG. 147 depicts linear relationships between total mass recovery(recovery (vol %)) versus API gravity (°) of the produced hydrocarbonsfor three different tar sands formations. Athabasca (Canada) tar sands9260 shows the highest recovery for a value of API gravity. Athabascashows the highest recovery because Athabasca tar sands have the highestinitial API gravity. Cerro Negro (Venezuela) tar sands 9262 shows aslightly lower recovery for a value of API gravity. Santa Cruz (UnitedStates) tar sands 9264 shows the lowest recovery for a value of APIgravity. Santa Cruz shows the lowest recovery because Santa Cruz tarsands have the lowest initial API gravity. Other relatively permeableformations may be tested similarly to produce similar plots. Theserelationships may be used to determine a desired operating range fortreating a relatively permeable formation. For example, the linearrelationship between recovery and API gravity may be used to determine abest operating range (e.g., a desired API gravity produces a specificrecovery value) based on market conditions such as the price of oil.

[1459] In an embodiment, a location from which the mixture is producedis varied by varying a production depth within a production well. Themixture may be produced from different portions of, or locations in, theformation to control the quality of the produced mixture. A productiondepth within a production well may be adjusted to vary a portion of theformation from which the mixture is produced. In some embodiments, theproduction depth is determined before producing the mixture from theformation. In other embodiments, the production depth may be adjustedduring production of the mixture to control the quality of the producedmixture. In certain embodiments, production depth within a productionwell includes varying a production location along a length of theproduction wellbore. For example, the production location may be at anydepth along the length of a substantially vertical production wellborelocated within the formation or at any position along the length of asubstantially horizontal production wellbore. Changing the depth of theproduction location within the formation may change a quality of themixture produced from the formation.

[1460] In some embodiments, varying the production location within aproduction well includes varying a packing height within the productionwell. For example, the packing height may be changed within theproduction well to change the portion of the production well thatproduces fluids from the formation. Packing within the production welltends to inhibit production of fluids at locations where the packing islocated. In other embodiments, varying the production location within aproduction well includes varying a location of perforations on theproduction wellbore used to produce the mixture. Perforations on theproduction wellbore may be used to allow fluids to enter into theproduction well. Varying the location of these perforations may change alocation or locations at which fluids can enter the production well.

[1461]FIG. 146 depicts a cross-sectional representation of an embodimentof production well 6710 placed in hydrocarbon layer 6704. Hydrocarbonlayer 6704 may include upper portion 8620, middle portion 8622, andlower portion 8624. Production well 6710 may be placed within all threeportions 8620, 8622, 8624 within hydrocarbon layer 6704 or within onlyone or more portions of the formation. As shown in FIG. 146, productionwell 6710 may be placed substantially vertically within hydrocarbonlayer 6704. Production well 6710, however, may be placed at other angles(e.g., horizontal or at other angles between horizontal and vertical)within hydrocarbon layer 6704 depending on, for example, a desiredproduct mixture, a depth of overburden 540, a desired production rate,etc.

[1462] Packing 8610 may be placed within production well 6710. Packing8610 tends to inhibit production of fluids at locations of the packingwithin the wellbore (i.e., fluids are inhibited from flowing intoproduction well 6710 at the packing). A height of packing 8610 withinproduction well 6710 may be adjusted to vary the depth in the productionwell from which fluids are produced. For example, increasing the packingheight decreases the maximum depth in the formation at which fluids maybe produced through production well 6710. Decreasing the packing heightwill increase the depth for production. In some embodiments, layers ofpacking 8610 may be placed at different heights within the wellbore toinhibit production of fluids at the different heights. Conduit 8611 maybe placed through packing 8610 to produce fluids entering productionwell 6710 beneath the packing layers.

[1463] One or more perforations 8612 may be placed along a length ofproduction well 6710.

[1464] Perforations 8612 may be used to allow fluids to enter intoproduction well 6710. In certain embodiments, perforations 8612 areplaced along an entire length of production well 6710 to allow fluids toenter into the production well at any location along the length of theproduction well. In other embodiments, locations of perforations 8612may be varied to adjust sections along the length of production well6710 that are used for producing fluids from the formation. In someembodiments, one or more perforations 8612 may be closed (shut-in) toinhibit production of fluids through the one or more perforations. Forexample, a sliding member may be placed over perforations 8612 that areto be closed to inhibit production. Certain perforations 8612 alongproduction well 6710 may be closed or opened at selected times to allowproduction of fluids at different locations along the production well atthe selected times.

[1465] In one embodiment, a first mixture is produced from upper portion8620. A second mixture may be produced from middle portion 8622. A thirdmixture may be produced from lower portion 8624. The first, second, andthird mixtures may be produced at different times during treatment ofthe formation. For example, the first mixture may be produced before thesecond mixture or the third mixture and the second mixture may beproduced before the third mixture. In certain embodiments, the firstmixture is produced such that the first mixture has an API gravitygreater than about 20°. The second mixture or the third mixture may alsobe produced such that each mixture has an API gravity greater than about20°. A time at which each mixture is produced with an API gravitygreater than about 20° may be different for each of the mixtures. Forexample, the first mixture may be produced at an earlier time thaneither the second or the third mixture. The first mixture may beproduced earlier because the first mixture is produced from upperportion 8620. Fluids in upper portion 8620 tend to have a higher APIgravity at earlier times than fluids in middle portion 8622 or lowerportion 8624 due to gravity drainage of heavier fluids (e.g., heavyhydrocarbons) in the formation and/or higher vapor phase production inhigher portions of the formation.

[1466] In an embodiment, a fluid produced from a portion of a relativelypermeable formation by an in situ process may include nitrogencontaining compounds. For example, less than about 0.5 weight % of thecondensable fluid may include nitrogen containing compounds or, forexample, less than about 0.1 weight % of the condensable fluid mayinclude nitrogen containing compounds. In addition, a fluid produced byan in situ process may include oxygen containing compounds (e.g.,phenolics). For example, less than about 1 weight % of the condensablefluid may include oxygen containing compounds or, for example, less thanabout 0.5 weight % of the condensable fluid may include oxygencontaining compounds. A fluid produced from a relatively permeableformation may also include sulfur containing compounds. For example,less than about 5 weight % of the condensable fluid may include sulfurcontaining compounds or, for example, less than about 3 weight % of thecondensable fluid may include sulfur containing compounds. In someembodiments, a weight percent of nitrogen containing compounds, oxygencontaining compounds, and/or sulfur containing compounds in acondensable fluid may be decreased by increasing a fluid pressure in arelatively permeable formation during an in situ process.

[1467] In an embodiment, condensable hydrocarbons of a fluid producedfrom a relatively permeable formation may include aromatic compounds.For example, greater than about 20 weight % of the condensablehydrocarbons may include aromatic compounds. In another embodiment, anaromatic compound weight percent may include greater than about 30weight % of the condensable hydrocarbons. The condensable hydrocarbonsmay also include di-aromatic compounds. For example, less than about 20weight % of the condensable hydrocarbons may include di-aromaticcompounds. In another embodiment, di-aromatic compounds may include lessthan about 15 weight % of the condensable hydrocarbons. The condensablehydrocarbons may also include tri-aromatic compounds. For example, lessthan about 4 weight % of the condensable hydrocarbons may includetri-aromatic compounds. In another embodiment, less than about 1 weight% of the condensable hydrocarbons may include tri-aromatic compounds.

[1468] In certain embodiments, some precipitation and/or non-dissolutionof asphaltenes may occur in heavy hydrocarbons and/or heavy hydrocarbonsmixed with light hydrocarbons within a relatively permeable formationduring a recovery process. Precipitation and/or non-dissolution of theasphaltenes may increase the quality of hydrocarbons produced from theformation. In some cases, the precipitated and/or non-dissolvedasphaltenes may be produced through further heating of the formationand/or injection of recovery fluid into the formation (e.g., injectionof a light hydrocarbon mixture or blending agent to form a produciblemixture including the asphaltenes).

[1469] In some embodiments, hydrocarbon fluids produced from arelatively permeable formation may have a relatively low acid number.“Acid number” is defined as the number of milligrams of KOH (potassiumhydroxide) required to neutralize one gram of oil (i.e., bring the oilto a pH of 7). Higher acid hydrocarbon fluids (e.g., greater than about1 mg/gram KOH) are typically more expensive to refine and generallyconsidered to have a less desirable quality. Generally, fluids with acidnumbers less than about 1 are desired. Heavy hydrocarbon fluids producedfrom relatively permeable formations using standard productiontechniques such as cold production or steam flooding may have a highacid number due to the presence of naphthenic, humic, or other acids inthe produced hydrocarbons. Hydrocarbon fluids produced from a formationusing an in situ recovery process (e.g., pyrolyzed fluids) may have alower acid number due to acid-reducing reactions during heating of theformation. For example, decarboxylation may reduce the amount ofcarboxylic acids in the formation during heating/pyrolyzation. In anembodiment, hydrocarbon fluids produced from a relatively permeableformation have an acid number of near zero. In certain embodiments,hydrocarbon fluids produced from a formation have acid numbers less thanabout 1 mg/gram KOH, less than about 0.8 mg/gram KOH, less than about0.6 mg/gram KOH, less than about 0.5 mg/gram KOH, less than about 0.25mg/gram KOH, or less than about 0.1 mg/gram KOH.

[1470] In certain embodiments, a portion of the formation proximate aproduction well may be hotter than other portions of the formation(e.g., an average temperature above about 300° C.). The increasedtemperature of the portion of the formation proximate the productionwell may be produced by additional heat provided by a heater placedwithin the production well, an additional heat source proximate theproduction well, and/or natural heating within the portion. Having anincreased temperature in the portion proximate the production well mayincrease and/or upgrade a quality of hydrocarbons produced through theproduction well (e.g., by increased cracking or thermal upgrading of thehydrocarbons). In addition, a quality of hydrocarbons produced may befurther increased by cracking of hydrocarbons or reaction ofhydrocarbons within the production well.

[1471] Increasing heating proximate a production well, however, mayincrease the possibility of coking at the production well. In someembodiments, operating conditions within the formation may be controlledto inhibit coking of a production well. In one embodiment, heat outputfrom a heat source proximate the production well may be controlled toinhibit coking of the production well. For example, the heat source canbe turned down and/or off when conditions (e.g., temperature) at theproduction well begin to favor coking at the production well. Forexample, coke may form at temperatures above about 400° C. In certainembodiments, heat provided from the heat source may be turned downand/or off during a time at which a mixture is produced through theproduction well. The heat provided may be turned on and/or increasedwhen the quality of produced fluid is below a desired quality. Inanother embodiment, a production well is located at a sufficientdistance from each of the heat sources in the formation such that atemperature at the production well inhibits coking at the productionwell.

[1472] In other embodiments, steam may be added to the formation byadding water or steam through a conduit in a production well or otherwellbore. In some embodiments, steam may be produced by evaporation ofwater within the formation. The additional steam may inhibit cokeformation proximate the production well. The steam may react with thecoke to form carbon dioxide, carbon monoxide, and/or hydrogen. Incertain embodiments, air may be periodically injected through a conduit(e.g., a conduit in a production well) to oxidize any coke formed at ornear a production well.

[1473] In an embodiment of a system using heat sources, a material(e.g., a cement and/or polymer foam) may be injected into the formationto inhibit fingering and/or breakthrough of gases within the formation.The material may inhibit fluid flow through channels adjacent to theheat sources. The use of such a material may provide a more uniform flowof mobilized fluids and increase the recovery of fluids from theformation.

[1474] An in situ process may be used to provide heat to mobilize and/orpyrolyze hydrocarbons within a relatively permeable formation to producehydrocarbons from the formation that are not technically or economicallyproducible using current production techniques such as surface mining,solution extraction, steam injection, etc. Such hydrocarbons may existin relatively deep, relatively permeable formations. For example, suchhydrocarbons may exist in a relatively permeable formation that isgreater than about 500 m below a ground surface but less than about 700m below the surface. Hydrocarbons within these relatively deep,relatively permeable formations may still be at a relatively cooltemperature such that the hydrocarbons are substantially immobile.Hydrocarbons found in deeper formations (e.g., a depth greater thanabout 700 m below the surface) may be somewhat more mobile due toincreased natural heating of the formations as formation depth increasesbelow the surface. Typically, the temperature in the formation increasesabout 2° C. to about 4° C. for every 100 meters in depth below thesurface. The temperature at a certain depth may vary, however, dependingon, for example, the surface temperature which may be anywhere fromabout −5° C. to about 30° C. Hydrocarbons may be more readily producedfrom these deeper formations because of their mobility. However, thesehydrocarbons will generally be heavy hydrocarbons with an API gravitybelow about 20°. In some embodiments, the API gravity may be below about15° or below about 10°.

[1475] Heavy hydrocarbons produced from a relatively permeable formationmay be mixed with light hydrocarbons so that the heavy hydrocarbons canbe transported to a surface facility (e.g., pumping the hydrocarbonsthrough a pipeline). In some embodiments, the light hydrocarbons (suchas naphtha or gas condensate) are brought in through a second pipeline(or are trucked) from other areas (such as a surface facility or anotherproduction site) to be mixed with the heavy hydrocarbons. The cost ofpurchasing and/or transporting the light hydrocarbons to a formationsite can add significant cost to a process for producing hydrocarbonsfrom a formation. In an embodiment, producing the light hydrocarbons ator near a formation site (e.g., less than about 100 km from theformation site) that produces heavy hydrocarbons instead of using asecond pipeline for supply of the light hydrocarbons may allow for useof the second pipeline for other purposes. The second pipeline may beused, in addition to a first pipeline already used for pumping producedfluids, to pump produced fluids from the formation site to a surfacefacility. Use of the second pipeline for this purpose may furtherincrease the economic viability of producing light hydrocarbons (i.e.,blending agents) at or near the formation site. Another option is tobuild a surface facility or refinery at a formation site. However, thiscan be expensive and, in some cases, not possible.

[1476] In an embodiment, light hydrocarbons (e.g., a blending agent) maybe produced at or near a formation site that produces heavy hydrocarbons(i.e., near the production site of heavy hydrocarbons). The lighthydrocarbons may be mixed with heavy hydrocarbons to produce atransportable mixture. The transportable mixture may be introduced intoa first pipeline used to transport fluid to a remote refinery ortransportation facility, which may be located more than about 100 kmfrom the production site. The transportable mixture may also beintroduced into a second pipeline that was previously used to transporta blending agent (e.g., naphtha, condensate, etc.) to or near theproduction site. Producing the blending agent at or near the productionsite may allow the ability to significantly increase throughput to theremote refinery or transportation facility without installation ofadditional pipelines. Additionally, the blending agent used may berecovered and sold from the refinery instead of being transported backto the heavy hydrocarbon production site. The transportable mixture mayalso be used as a raw material feed for a production process at theremote refinery.

[1477] Throughput of heavy hydrocarbons to an existing remote surfacefacility may be a limiting factor in embodiments that use a two pipelinesystem with one of the pipelines dedicated to transporting a blendingagent to the heavy hydrocarbon production site. Using a blending agentproduced at or near the heavy hydrocarbon production site may allow fora significant increase in the throughput of heavy hydrocarbons to theremote surface facility. For example, a pair of pipelines with ablending agent to heavy hydrocarbon ratio of 1:2 may transport twice asmuch oil if recycling of the blending agent is not necessary. In someembodiments, the blending agent may be used to clean tanks, pipes,wellbores, etc. The blending agent may be used for such purposes withoutprecipitating out components (e.g., asphaltenes or waxes) cleaned fromthe tanks, pipes, or wellbores.

[1478] In an embodiment, heavy hydrocarbons are produced as a firstmixture from a first section of a relatively permeable formation. Heavyhydrocarbons may include hydrocarbons with an API gravity below about20°, 15°, or 10°. Heat provided to the first section may mobilize atleast some hydrocarbons within the first section. The first mixture mayinclude at least some mobilized hydrocarbons from the first section.Heavy hydrocarbons in the first mixture may include a relatively highasphaltene content compared to saturated hydrocarbon content. Forexample, heavy hydrocarbons in the first mixture may include anasphaltene content to saturated hydrocarbon content ratio greater thanabout 1, greater than about 1.5, or greater than about 2.

[1479] Heat provided to a second section of the formation may pyrolyzeat least some hydrocarbons within the second section. A second mixturemay be produced from the second section. The second mixture may includeat least some pyrolyzed hydrocarbons from the second section. Pyrolyzedhydrocarbons from the second section may include light hydrocarbonsproduced in the second section. The second mixture may includerelatively higher amounts (as compared to heavy hydrocarbons orhydrocarbons found in the formation) of hydrocarbons such as naphtha,methane, ethane, or propane (i.e., saturated hydrocarbons) and/oraromatic hydrocarbons. In some embodiments, light hydrocarbons mayinclude an asphaltene content to saturated hydrocarbon content ratioless than about 0.5, less than about 0.05, or less than about 0.005.

[1480] A condensable fraction of the light hydrocarbons of the secondmixture may be used as a blending agent. The presence of compounds inthe blending agent in addition to naphtha may allow the blending agentto dissolve a large amount of asphaltenes and/or solid hydrocarbons. Theblending agent may be used to clean tanks, pipelines or other vesselsthat have solid (or semi-solid) hydrocarbon deposits.

[1481] The light hydrocarbons of the second mixture may include lessnitrogen, oxygen, sulfur, and/or metals (e.g., vanadium or nickel) thanheavy hydrocarbons. For example, light hydrocarbons may have a nitrogen,oxygen, and sulfur combined weight percentage of less than about 5%,less than about 2%, or less than about 1%. Heavy hydrocarbons may have anitrogen, oxygen, and sulfur combined weight percentage greater thanabout 10%, greater than about 15%, or greater than about 18%. Lighthydrocarbons may have an API gravity greater than about 20°, greaterthan about 30°, or greater than about 40°.

[1482] The first mixture and the second mixture may be blended toproduce a third mixture. The third mixture may be formed in a surfacefacility located at or near production facilities for the heavyhydrocarbons. The third mixture may have a selected API gravity. Theselected API gravity may be at least about 10° or, in some embodiments,at least about 20° or 30°. The API gravity may be selected to allow thethird mixture to be efficiently transported (e.g., through a pipeline).

[1483] A ratio of the first mixture to the second mixture in the thirdmixture may be determined by the API gravities of the first mixture andthe second mixture. For example, the lower the API gravity of the firstmixture, the more of the second mixture that may be needed to produce aselected API gravity in the third mixture. Likewise, if the API gravityof the second mixture is increased, the ratio of the first mixture tothe second mixture may be increased. In some embodiments, a ratio of thefirst mixture to the second mixture in the third mixture is at leastabout 3:1. Other ratios may be used to produce a third mixture with adesired API gravity. In certain embodiments, a ratio of the firstmixture to the second mixture is chosen such that a total mass recoveryfrom the formation will be as high as possible. In one embodiment, theratio of the first mixture to the second mixture may be chosen such thatat least about 50% by weight of the initial mass of hydrocarbons in theformation is produced. In other embodiments, at least about 60% byweight or at least about 70% by weight of the initial mass ofhydrocarbons may be produced. In some embodiments, the first mixture andthe second mixture are blended in a specific ratio that may increase thetotal mass recovery from the formation compared to production of onlythe second mixture from the formation (i.e., in situ processing of theformation to produce light hydrocarbons).

[1484] The ratio of the first mixture to the second mixture in the thirdmixture may be selected based on a desired viscosity, desired boilingpoint, desired composition, desired ratio of components (e.g., a desiredasphaltene to saturated hydrocarbon ratio or a desired aromatichydrocarbon to saturated hydrocarbon ratio), and/or desired density ofthe third mixture. The viscosity and/or density may be selected suchthat the third mixture is transportable through a pipeline or usable ina surface facility. In some embodiments, the viscosity (at about 4° C.)may be selected to be less than about 7500 centistokes (cs) less thanabout 2000 cs, less than about 100 cs, or less than about 10 cs.Centistokes is a unit of kinematic viscosity. Kinematic viscositymultiplied by the density yields absolute viscosity. The density (atabout 4° C.) may be selected to be less than about 1.0 g/cm³, less thanabout 0.95 g/cm³ or less than about 0.9 g/cm³. The asphaltene tosaturated hydrocarbon ratio may be selected to be less than about 1,less than about 0.9, or less than about 0.7. The aromatic hydrocarbon tosaturated hydrocarbon ratio may be selected to be less than about 4,less than about 3.5, or less than about 2.5.

[1485] The viscosity of a third mixture may have improved viscositycompared to conventionally produced crude oils. For example, in “TheViscosity of Air, Natural Gas, Crude Oil and Its Associated Gases at OilField Temperatures and Pressures” by Carlton Beal, AIME Transactions,vol. 165, p. 94, 1946, which is incorporated by reference as if fullyset forth herein. Beal found a correlation for 655 samples of crude oilthat indicates an average viscosity of about 50 centipoise (cp) at 38°C. for crude oil with an API gravity of 24°. The lowest averageviscosity was found to be about 20 cp at 38° C. for 200 California crudeoil samples with an API gravity of 24°. A third mixture produce bymixing of a first mixture and a second mixture may have a viscosity ofabout 11 cp at 38° C. and 24° API. Thus, a mixture produced by mixingheavy hydrocarbons with light hydrocarbons produced by an in situconversion process may have improved viscosity compared to typicalproduced crude oils.

[1486] In an embodiment, the ratio of the first mixture to the secondmixture in the third mixture is selected based on the relative stabilityof the third mixture. A component or components of the third mixture mayprecipitate out of the third mixture. For example, asphalteneprecipitation may be a problem for some mixtures of heavy hydrocarbonsand light hydrocarbons. Asphaltenes may precipitate when fluid isde-pressurized (e.g., removed from a pressurized formation or vessel)and/or there is a change in mixture composition. For the third mixtureto be transportable through a pipeline or usable in a surface facility,the third mixture may need a minimum relative stability. The minimumrelative stability may include a ratio of the first mixture to thesecond mixture such that asphaltenes do not precipitate out of the thirdmixture at ambient and/or elevated temperatures. Tests may be used todetermine desired ratios of the first mixture to the second mixture thatwill produce a relatively stable third mixture. For example, inducedprecipitation, chromatography, titration, and/or laser techniques may beused to determine the stability of asphaltenes in the third mixture. Insome embodiments, asphaltenes precipitate out of a mixture but are heldsuspended in the mixture and, hence, the mixture may be transportable. Ablending agent produced by an in situ process may have excellentblending characteristics with heavy hydrocarbons (i.e., low probabilityfor precipitation of heavy hydrocarbons from a mixture with the blendingagent).

[1487] In certain embodiments, resin content in the second mixture(i.e., light hydrocarbon mixture) may determine the stability of thethird mixture. For example, resins such as maltenes or resins containingheteroatoms such as N, S, or O may be present in the second mixture.These resins may enhance the stability of a third mixture produced bymixing a first mixture with the second mixture. In some cases, theresins may suspend asphaltenes in the mixture and inhibit asphalteneprecipitation.

[1488] In certain embodiments, market conditions may determinecharacteristics of a third mixture. Examples of market conditions mayinclude, but are not limited to, demand for a selected octane ofgasoline, demand for heating oil in cold weather, demand for a selectedcetane rating in a diesel oil, demand for a selected smoke point for jetfuel, demand for a mixture of gaseous products for chemical synthesis,demand for transportation fuels with a certain sulfur or oxygenatecontent, or demand for material in a selected chemical process.

[1489] In an embodiment, a blending agent may be produced from a sectionof a relatively permeable formation (e.g., a tar sands formation).“Blending agent” is a material that is mixed with another material toproduce a mixture having a desired property (e.g., viscosity, density,API gravity, etc.). The blending agent may include at least somepyrolyzed hydrocarbons. The blending agent may include properties of thesecond mixture of light hydrocarbons described above. For example, theblending agent may have an API gravity greater than about 20°, greaterthan about 30°, or greater than about 40°. The blending agent may beblended with heavy hydrocarbons to produce a mixture with a selected APIgravity. For example, the blending agent may be blended with heavyhydrocarbons with an API gravity below about 15° to produce a mixturewith an API gravity of at least about 20°. In certain embodiments, theblending agent may be blended with heavy hydrocarbons to produce atransportable mixture (e.g., movable through a pipeline). In someembodiments, the heavy hydrocarbons are produced from another section ofthe relatively permeable formation. In other embodiments, the heavyhydrocarbons may be produced from another relatively permeable formationor any other formation containing heavy hydrocarbons, at the same siteor another site.

[1490] In some embodiments, the first section and the second section ofthe formation may be at different depths within the same formation. Forexample, the heavy hydrocarbons may be produced from a section having adepth between about 500 m and about 1500 m, a section having a depthbetween about 500 m and about 1200 m, or a section having a depthbetween about 500 m and about 800 m. At these depths, the heavyhydrocarbons may be somewhat mobile (and producible) due to a relativelyhigher natural temperature in the reservoir. The light hydrocarbons maybe produced from a section having a depth between about 10 m and about500 m, a section having a depth between about 10 m and about 400 m, or asection having a depth between about 10 m and about 250 m. At theseshallower depths, heavy hydrocarbons may not be readily produciblebecause of the lower natural temperatures at the shallower depths. Inaddition, the API gravity of heavy hydrocarbons may be lower atshallower depths due to increased water washing, loss of lighterhydrocarbons due to leaks in the seal of the formation, and/or bacterialdegradation. In other embodiments, heavy hydrocarbons and lighthydrocarbons are produced from first and second sections that are at asimilar depth below the surface. In another embodiment, the lighthydrocarbons and the heavy hydrocarbons are produced from differentformations. The different formations, however, may be located near eachother.

[1491] In an embodiment, heavy hydrocarbons are cold produced from aformation (e.g., a tar sands formation in the Faja (Venezuela)) atdepths between about 760 m and about 1070 m. The produced hydrocarbonsmay have an API gravity of less than about 9°. Cold production of heavyhydrocarbons is generally defined as the production of heavyhydrocarbons without providing heat (or providing relatively littleheat) to the formation or the production well. In other embodiments, theheavy hydrocarbons may be produced by steam injection or a mixture ofsteam injection and cold production. The heavy hydrocarbons may be mixedwith a blending agent to transport the produced heavy hydrocarbonsthrough a pipeline. In one embodiment, the blending agent is naphtha.Naphtha may be produced in surface facilities that are located remotelyfrom the formation.

[1492] In other embodiments, the heavy hydrocarbons may be mixed with ablending agent produced from a shallower section of the formation usingan in situ conversion process. The shallower section may be at a depthless than about 400 m (e.g., less than about 150 m). The shallowersection of the formation may contain heavy hydrocarbons with an APIgravity of less than about 7°. The blending agent may include lighthydrocarbons produced by pyrolyzing at least some of the heavyhydrocarbons from the shallower section of the formation. The blendingagent may have an API gravity above about 35° (e.g., above about 40°).

[1493] In certain embodiments, a blending agent may be produced in afirst portion of a relatively permeable formation and injected (e.g.,into a production well) into a second portion of the relativelypermeable formation (or, in some embodiments, a second portion inanother relatively permeable formation). Heavy hydrocarbons may beproduced from the second portion (e.g., by cold production). Mixingbetween the blending agent may occur within the production well and/orwithin the second portion of the formation. The blending agent may beproduced through a production well in the first portion and pumped to aproduction well in the second portion. In some embodiments,non-hydrocarbon fluids (e.g., water or carbon dioxide), vapor-phasehydrocarbons, and/or other undesired fluids may be separated from theblending agent prior to mixing with heavy hydrocarbons.

[1494] Injecting the blending agent into a portion of a relativelypermeable formation may provide mixing of the blending agent and heavyhydrocarbons in the portion. The blending agent may be used to assist inthe production of heavy hydrocarbons from the formation. The blendingagent may reduce a viscosity of heavy hydrocarbons in the formation.Reducing the viscosity of heavy hydrocarbons in the formation may reducethe possibility of clogging or other problems associated with coldproducing heavy hydrocarbons. In some embodiments, the blending agentmay be at an elevated temperature and be used to provide at least someheat to the formation to increase the mobilization (i.e., reduce theviscosity) of heavy hydrocarbons within the formation. The elevatedtemperature of the blending agent may be a temperature proximate thetemperature at which the blending agent is produced minus some heatlosses during production and transport of the blending agent. In certainembodiments, the blending agent may be pumped through an insulatedpipeline to reduce heat losses during transport.

[1495] The blending agent may be mixed with the cold produced heavyhydrocarbons in a selected ratio to produce a third mixture with aselected API gravity. For example, the blending agent may be mixed withcold produced heavy hydrocarbons in a 1 to 2 ratio or a 1 to 4 ratio toproduce a third mixture with an API gravity greater than about 20°. Insome embodiments, other ratios of blending agent to heavy hydrocarbonsmay be selected as desired to produce a third mixture with one or moreselected properties. In certain embodiments, the third mixture may havean overall API gravity greater than about 25° or an API gravitysufficiently high such that the third mixture is transportable through aconduit or pipeline. In some embodiments, the third mixture ofhydrocarbons may have an API gravity between about 20° and about 45°. Inother embodiments, the blending agent may be mixed with cold producedheavy hydrocarbons to produce a third mixture with a selected viscosity,a selected stability, and/or a selected density.

[1496] The third mixture may be transported through a conduit, such as apipeline, between the formation and a surface facility or refinery. Thethird mixture may be transported through a pipeline to another locationfor further transportation (e.g., the mixture can be transported to afacility at a river or a coast through the pipeline where the mixturecan be further transported by tanker to a processing plant or refinery).Producing the blending agent at the formation site (i.e., producing theblending agent from the formation) may reduce a total cost for producinghydrocarbons from the formation. In addition, producing the thirdhydrocarbon mixture at a formation site may eliminate a need for aseparate supply of light hydrocarbons and/or construction of a surfacefacility at the site.

[1497] In an embodiment, a mixture of hydrocarbons may include about 20weight % light hydrocarbons (or blending agent) or greater (e.g., about50 weight % or about 80 weight % light hydrocarbons) and about 80 weight% heavy hydrocarbons or less (e.g., about 50 weight % or about 20 weight% heavy hydrocarbons). The weight percentage of light hydrocarbons andheavy hydrocarbons may vary depending on, for example, a weightdistribution (or API gravity) of light and heavy hydrocarbons, arelatively stability of the third mixture or a desired API gravity ofthe mixture. For example, in some embodiments, the weigh percentage oflight hydrocarbons in the mixture may be less than 50 weight % or lessthan 20%. In certain embodiments, the weight percentage of lighthydrocarbons may be selected to blend the least amount of lighthydrocarbons with heavy hydrocarbons that produces a mixture with adesired density or viscosity. Reducing the viscosity of heavyhydrocarbons with a blending agent may make it easier to separate waterfrom the blended hydrocarbons.

[1498]FIG. 148 depicts a plan view of an embodiment of a relativelypermeable formation used to produce a first mixture that is blended witha second mixture. Relatively permeable formation 9300 may include firstsection 9304 and second section 9302. First section 9304 may be atdepths greater than, for example, about 800 m below a surface of theformation. Heavy hydrocarbons in first section 9304 may be producedthrough production well 9306 placed in the first section. Heavyhydrocarbons in first section 9304 may be produced without heatingbecause of the depth of the first section. First section 9304 may bebelow a depth at which natural heating mobilizes heavy hydrocarbonswithin the first section. In some embodiments, at least some heat may beprovided to first section 9304 to mobilize fluids within the firstsection.

[1499] Second section 9302 may be heated using heat sources 6700 placedin the second section. Heat sources 6700 are depicted as substantiallyhorizontal heat sources in FIG. 148. Heat provided by heat sources 6700may pyrolyze at least some hydrocarbons within second section 9302.Pyrolyzed fluids may be produced from second section 9302 throughproduction well 6710. Production well 6710 is depicted as asubstantially vertical production well in FIG. 148.

[1500] In an embodiment, heavy hydrocarbons from first section 9304 areproduced in a first mixture through production well 9306. Lighthydrocarbons (i.e., pyrolyzed hydrocarbons) may be produced in a secondmixture through production well 6710. The first mixture and the secondmixture may be mixed to produce a third mixture in surface facility9310. The first and the second mixture may be mixed in a selected ratioto produce a desired third mixture. The third mixture may be transportedthrough pipeline 9312 to a production facility or a transportationfacility. The production facility or transportation facility may belocated remotely from surface facility 9310. In some embodiments, thethird mixture may be trucked or shipped to a production facility ortransportation facility. In certain embodiments, surface facility 9310may be a simple mixing station to combine the mixtures produced fromproduction well 9306 and production well 6710.

[1501] In certain embodiments, the blending agent produced from secondsection 9302 may be injected through production well 9306 into firstsection 9304. A mixture of light hydrocarbons and heavy hydrocarbons maybe produced through production well 9306 after mixing of the blendingagent and heavy hydrocarbons in first section 9304. In some embodiments,the blending agent may be produced by separating non-desirablecomponents (e.g., water) from a mixture produced from second section9302. The blending agent may be produced in surface facility 9310. Theblending agent may be pumped from surface facility 9310 throughproduction well 9306 and into first section 9304.

[1502] FIGS. 149-155 depict results from an experiment. In theexperiment, blending agent 102 produced by pyrolysis was mixed withAthabasca tar (heavy hydrocarbons 110) in three blending mixtures ofdifferent ratios. First mixture 9645 included 80% blending agent 9644and 20% heavy hydrocarbons 9648. Second mixture 9646 included 50%blending agent 9644 and 50% heavy hydrocarbons 9648. Third mixture 9647included 20% blending agent 9644 and 80% heavy hydrocarbons 9648.Composition, physical properties, and asphaltene stability were measuredfor the blending agent, heavy hydrocarbons, and each of the mixtures.

[1503] TABLE 1 presents results of composition measurements of themixtures. SARA analysis determined composition on a topped oil basis.SARA analysis includes a combination of induced precipitation (forasphaltenes) and column chromatography. Whole oil basis compositionswere also determined. TABLE 1 Whole Blend Ratio Topped oil basis (SARA)oil basis Blend 9648 9644 Sat Aro NSO Asph NSO Asph 9644  0:100 43.446.5 9.8 0.23 0.42 0.01 9645 20:80 20.6 49.4 20.6 9.30 4.91 2.21 964650:50 15.3 51.5 20.1 13.0 10.7 6.91 9647 80:20 14.4 51.5 20.8 13.1 16.410.3 9648 100:0  12.5 52.8 20.2 14.5 18.4 13.2

[1504]FIG. 149 depicts asphaltene content (on a whole oil basis) in theblend versus percent blending agent in the mixture for each of the threemixtures (9645, 9646, and 9647), blending agent 9644, and heavyhydrocarbons 9648. As shown in FIG. 149, asphaltene content on a wholeoil basis varies linearly with the percentage of blending agent 9644 inthe mixture.

[1505]FIG. 150 depicts SARA results (saturate/aromatic ratio versusasphaltene/resin ratio) for each of the blends (9644, 9645, 9646, 9647,and 9648). The line in FIG. 150 represents the differentiation betweenstable mixtures and unstable mixtures based on SARA results. The toppingprocedure used for SARA removed a greater proportion of the contributionof blending agent 9644 (as compared to whole oil analysis) and resultedin the non-linear distribution in FIG. 150. First mixture 9645, secondmixture 9646, and third mixture 9647 plotted closer to heavyhydrocarbons 9648 than blending agent 9644. In addition, second mixture9646 and third mixture 9647 plotted relatively closely. All blends(9644, 9645, 9646, 9647, and 9648) plotted in a region of marginalstability.

[1506] Blending agent 9644 included very little asphaltene (0.01% byweight, whole oil basis). Heavy hydrocarbons 9648 included about 13.2%by weight (whole oil basis) with the amount of asphaltenes in themixtures (9645, 9646, and 9647) varying between 2.2% by weight and 10.3%by weight on a whole oil basis. Other indicators of the gross oilproperties is the ratio between saturates and aromatics and the ratiobetween asphaltenes and resins. The asphaltene/resin ratio was lowestfor first mixture 9645, which has the largest percentage of blendingagent 9644. Second mixture 9646 and third mixture 9647 had relativelysimilar asphaltene/resin ratios indicating that the majority of resinsin the mixtures are due to contribution from heavy hydrocarbons 9648.The saturate/aromatic ratio was relatively similar for each of themixtures.

[1507] Density and viscosity of the mixtures were measured at threetemperatures 4.4° C. (40° F.), 21° C. (70° F.), and 32° C. (90° F.). Thedensity and API gravity of the mixtures were also determined at 15° C.(60° F.) and used to calculate API gravities at other temperatures. Inaddition, a Floc Point Analyzer (FPA) value was determined for each ofthe three blended mixtures (9645, 9646, and 9647). FPA is determined byn-heptane titration. The floc point is detected with a near infraredlaser. The light source is blocked by asphaltenes precipitating out ofsolution. The FPA test was calibrated with a set of known problem andnon-problem mixtures. Generally, FPA values less than 2.5 are consideredunstable, greater than 3.0 are considered stable, and 2.5-3.0 areconsidered marginal. TABLE 2 presents values for FPA, density,viscosity, and API gravity for the three blended mixtures at fourtemperatures. TABLE 2 Temperature: 15° C. 4.4° C. 21° C. 32° C. Spec.Density Density Visc. Density Visc. Density Visc. Blend FPA Grav. (g/cc)API (g/cc) (cs) API (g/cc) (cs) API (g/cc) (cs) API 9645 1.5 0.8450.8443 35.9 0.8535 4.20 34.12 0.8405 2.95 36.7 0.8324 2.39 39.3 9646 2.20.909 0.9086 24.1 0.9177 53.9 22.54 0.9052 25.6 24.7 0.8974 16.2 26.09647 2.8 0.976 0.9751 13.5 0.9839 5934 12.18 0.9717 1267 14.0 0.9643531.6 15.1

[1508] FPA tests showed that the mixtures containing lower amounts ofheavy hydrocarbons were less stable. The lower stability was likely dueto the proportion of aliphatic components already in these mixtures,which reduces asphaltene solubility. First mixture 9645 was the leaststable with a FPA value of 1.5, indicating instability with respect toasphaltene precipitation. FIG. 151 illustrates near infraredtransmittance versus volume (ml) of n-heptane added to first mixture9645. The peak in the plot for first mixture 9645 illustrates thatprecipitation of asphaltenes occurs rapidly with the addition ofn-heptane.

[1509] Second mixture 9646 exhibited different behavior. Second mixture9646 had a FPA value of 2.2 indicating instability with respect toasphaltene precipitation. FIG. 152 illustrates near infraredtransmittance versus volume (ml) of n-heptane added to second mixture9646. Two distinct peaks are seen in FIG. 152 indicating thatasphaltenes were precipitated, re-dissolved, and then re-precipitatedwith continuous addition of n-heptane.

[1510]FIG. 153 illustrates near infrared transmittance versus volume(ml) of n-heptane added to third mixture 9647. Third mixture 9647 showedsimilar behavior to second mixture 9646 as shown in FIGS. 152 and 153.The first peak in FIG. 153, however, was less pronounced than the firstpeak in FIG. 152. The FPA value of 2.8 found for third mixture 9647indicates marginal stability for the third mixture. Slow homogenization,associated with a high viscosity of the sample mixtures, is most likelyresponsible for the appearance of double peaks in FIGS. 152 and 153.

[1511] Each of the mixtures (9645, 9646, and 9647) showed relativelysimilar changes in density with increasing temperature (as shown in FIG.154). API values increased correspondingly with decreasing density.Viscosity changes, however, varied between each of the mixtures.

[1512] First mixture 9645 was the least affected by temperature withviscosity values at 21° C. and 32° C. determined to be about 70% andabout 57% of that at 4.4° C., respectively. Second mixture 9646 hadviscosity values that decreased to values (of that at 4.4° C.) of about48% at 21° C. and about 30% at 32° C. Third mixture 9647 was the mostaffected by temperature with viscosity values of about 21% and about 9%at 21° C. and 32° C., respectively. Viscosity changes are approximatelylinear on a logarithmic plot of viscosity versus temperature as shown inFIG. 155.

[1513] Typically, a majority of relatively permeable formations arewater-wet. A substantial majority of flow within the formation may occurwhile the formation remains water-wet (increased temperatures in theformation has not resulted in the vaporization of water in theformation). The formation being water-wet may help the efficiency ofgravity-produced flow in the formation during early stages ofproduction. The formation may become more oil-wet as water evaporatesand/or as asphaltene is precipitated (asphaltene precipitation maydepend on oil composition, pressure and temperature, and/or CO₂ level).Later stages of production may occur when the reservoir is oil-wet.Oil-wet production may increase the efficiency of film drainage duringthe later stages of production.

[1514] In some embodiments, permeability of a relatively permeableformation may be improved upon heating of the relatively permeableformation. Some relatively permeable formations include clays such askaolinite between the grains. The clays may reduce permeability in theformation. These clays may dissolve at temperatures approaching andabove about 250° C. in the presence of steam. The steam may be generatedby water evaporation in the formation. Dissolving the clays willincrease the permeability of the formation. Permeability may also beincreased due to reduction in effective stress of the formation as fluidpressure increases in the formation during heating. The fluid pressuremay increase in the pore spaces of the formation during heating. Thermalexpansion of the fluids may produce dilatancy effects in the formation.“Dilatancy” is the tendency of rocks to expand along minute fracturesimmediately prior to failure. Dilatancy may increase permeability in theformation.

[1515] In some embodiments, the formation may be treated to provide apathway for vertical drainage of fluids if no such pathway exists. Forexample, the formation may be fractured hydraulically or by othertechniques.

[1516] Toward the end of production, oil quality may also improve ascompared to initial oil quality. Carbon dioxide produced in theformation may cause non-cracking related upgrading (e.g., by asphalteneprecipitation or viscosity reduction) of fluids within the formation.

[1517] In some embodiments, injection of carbon dioxide can be used tosequester carbon dioxide within the formation. As production from theformation is slowed and/or halted, carbon dioxide may be sequestered inthe formation at relatively high pressures. This may reduce carbon taxesassociated with a production process and/or create environmentalemissions credit.

[1518] In certain embodiments, evaporation of water within the formationmay increase pressure in the formation due to production of steam. Theproduced steam may increase flow of mobilized fluids within theformation.

[1519] In some embodiments, a relatively permeable formation may includetar mats. Tar mats may form by a variety of methods. One possibility fortar mat formation is through deasphalting. Deasphalting may includecompositional gravity segregation as well as a destabilization of an oildue to gas addition. Gas addition may be provided by migration fromadjacent areas and/or by gas formation within the formation. Anotherpossibility for tar mat formation may be by biodegradation and/or waterwashing. In addition, there is the possibility of in situ maturation,with lighter oil and pyrobitumen forming from a heavier precursor.Another formation possibility is asphaltenic precipitation due topressure decline during uplift of a formation. The chemistry of a tarmat may be highly asphaltenic (i.e., complex hydrocarbons with highmolecular weights). Reservoirs with basal or lateral tar mats existworldwide.

[1520] In certain embodiments, a tar mat may inhibit oil production bywater drive. In such embodiments, heater wells may be used to heat a tarmat zone sufficiently to remove bitumen from the formation or lower theoil viscosity in the tar mat. This process may significantly improvepermeability and flow characteristics within the tar mat zone, thusallowing enhanced production due to a natural water drive or some otherdrive mechanism (e.g., water or steam injection).

[1521] Several patterns of heat sources arranged in rings aroundproduction wells may be utilized to create a pyrolysis region around aproduction well in a relatively permeable formation. Various patternembodiments are shown in FIGS. 156-168.

[1522] Production wells 2701 and heat sources 2712 may be located at theapices of a triangular grid, as depicted in FIG. 156. The triangulargrid may be an equilateral triangular grid with sides of length s.Production wells 2701 may be spaced at a distance of about 1.732(s).Each production well 2701 may be disposed at a center of ring 2713 ofheat sources 2712 in a hexagonal pattern. Each heat source 2712 mayprovide substantially equal amounts of heat to three production wells.Therefore, each ring 2713 of six heat sources 2712 may contributeapproximately two equivalent heat sources per production well 2701.

[1523]FIG. 157 illustrates a pattern of production wells 2701 with aninner hexagonal ring 2713 and an outer hexagonal ring 2715 of heatsources 2712. In this pattern, production wells 2701 may be spaced at adistance of about 2(1.732)s. Heat sources 2712 may be located at allother grid positions. This pattern may result in a ratio of equivalentheat sources to production wells that may approach 11:1 (i.e., 6equivalent heat sources for ring 2713; (½)(6) or 3 equivalent heatsources for the 6 heat sources of ring 2715 between apices of thehexagonal pattern; and (⅓)(6) or 2 equivalent heat sources for the 6heat sources of nng 2715 at the apices of the hexagonal pattern).

[1524]FIG. 158 illustrates three rings of heat sources 2712 surroundingproduction well 2701. Production well 2701 may be surrounded by ring2713 of six heat sources 2712. Second hexagonally shaped ring 2716 oftwelve heat sources 2712 may surround ring 2713. Third ring 2718 of heatsources 2712 may include twelve heat sources that may providesubstantially equal amounts of heat to two production wells and six heatsources that may provide substantially equal amounts of heat to threeproduction wells. Therefore, a total of eight equivalent heat sourcesmay be disposed on third ring 2718. Production well 2701 may be providedheat from an equivalent of about twenty-six heat sources. FIG. 159illustrates an even larger pattern that may have a greater spacingbetween production wells 2701.

[1525]FIGS. 160, 161, 162, and 163 illustrate embodiments in which bothproduction wells and heat sources are located at the apices of atriangular grid. In FIG. 160, a triangular grid with a spacing of s mayhave production wells 2701 spaced at a distance of 2 s. A hexagonalpattern may include one ring 2730 of six heat sources 2732. Each heatsource 2732 may provide substantially equal amounts of heat to twoproduction wells 2701. Therefore, each ring 2730 of six heat sources2732 contributes approximately three equivalent heat sources perproduction well 2701.

[1526]FIG. 161 illustrates a pattern of production wells 2701 with innerhexagonal ring 2734 and outer hexagonal ring 2736. Production wells 2701may be spaced at a distance of 3 s. Heat sources 2732 may be located atapices of hexagonal ring 2734 and hexagonal ring 2736. Hexagonal ring2734 and hexagonal ring 2736 may include six heat sources each. Thepattern in FIG. 161 may result in a ratio of heat sources 2732 toproduction well 2701 of about eight.

[1527]FIG. 162 illustrates a pattern of production wells 2701 also withtwo hexagonal rings of heat sources surrounding each production well.Production well 2701 may be surrounded by ring 2738 of six heat sources2732. Production wells 2701 may be spaced at a distance of 4 s. Secondhexagonal ring 2740 may surround ring 2738. Second hexagonal ring 2740may include twelve heat sources 2732. This pattern may result in a ratioof heat sources 2732 to production wells 2701 that may approach fifteen.

[1528]FIG. 163 illustrates a pattern of heat sources 2732 with threerings of heat sources 2732 surrounding each production well 2701.Production wells 2701 may be surrounded by ring 2742 of six heat sources2732. Second ring 2744 of twelve heat sources 2732 may surround ring2742. Third ring 2746 of heat sources 2732 may surround second ring2744. Third ring 2746 may include 6 equivalent heat sources. Thispattern may result in a ratio of heat sources 2732 to production wells2701 that is about 24:1.

[1529]FIGS. 164, 165, 166, and 167 illustrate patterns in which theproduction well may be disposed at a center of a triangular grid suchthat the production well may be equidistant from the apices of thetriangular grid. In FIG. 164, the triangular grid of heater wells with aspacing of s may include production wells 2760 spaced at a distance ofs. Each production well 2760 may be surrounded by ring 2764 of threeheat sources 2762. Each heat source 2762 may provide substantially equalamounts of heat to three production wells 2760. Therefore, each ring2764 of three heat sources 2762 may contribute one equivalent heatsource per production well 2760.

[1530]FIG. 165 illustrates a pattern of production wells 2760 with innertriangular ring 2766 and outer hexagonal ring 2768. In this pattern,production wells 2760 may be spaced at a distance of 2 s. Heat sources2762 may be located at apices of inner triangular ring 2766 and outerhexagonal ring 2768. Inner triangular ring 2766 may contribute threeequivalent heat sources per production well 2760. Outer hexagonal ring2768 containing three heater wells may contribute one equivalent heatsource per production well 2760. Thus, a total of four equivalent heatsources may provide heat to production well 2760.

[1531]FIG. 166 illustrates a pattern of production wells with one innertriangular ring of heat sources surrounding each production well and oneirregular hexagonal outer ring. Production wells 2760 may be surroundedby ring 2770 of three heat sources 2762. Production wells 2760 may bespaced at a distance of 3 s. Irregular hexagonal ring 2772 of nine heatsources 2762 may surround ring 2770. This pattern may result in a ratioof heat sources 2762 to production wells 2760 of about 9:1.

[1532]FIG. 167 illustrates triangular patterns of heat sources withthree rings of heat sources surrounding each production well. Productionwells 2760 may be surrounded by ring 2774 of three heat sources 2762.Irregular hexagon pattern 2776 of nine heat sources 2762 may surroundring 2774. Third set 2778 of heat sources 2762 may surround irregularhexagonal pattern 2776. Third set 2778 may contribute four equivalentheat sources to production well 2760. A ratio of equivalent heat sourcesto production well 2760 may be sixteen.

[1533]FIG. 168 depicts an embodiment of a pattern of heat sources 2705arranged in a triangular pattern. Production well 2701 may be surroundedby triangles 2780, 2782, and 2784 of heat sources 2705. Heat sources2705 in triangles 2780, 2782, and 2784 may provide heat to theformation. The provided heat may raise an average temperature of theformation to a pyrolysis temperature. Pyrolyzation fluids may flow toproduction well 2701. Formation fluids may be produced in productionwell 2701.

[1534]FIG. 169 illustrates an example of a square pattern of heatsources 3000 and production wells 3002. Heat sources 3000 are disposedat vertices of squares 3010. Production well 3002 is placed in a centerof every third square in both x- and y-directions. Midlines 3006 areformed equidistant to two production wells 3002, and perpendicular to aline connecting such production wells. Intersections of midlines 3006 atvertices 3008 form unit cell 3012. Heat source 3000 a is completelywithin unit cell 3012. Heat source 3000 b and heat source 3000 c areonly partially within unit cell 3012. Only the one-half fraction of heatsource 3000 b and the one-quarter fraction of heat source 3000 c withinunit cell 3012 provide heat within unit cell 3012. The fraction of heatsource 3000 outside of unit cell 3012 may provide heat outside of unitcell 3012. The number of heat sources 3000 within one unit cell 3012 isa ratio of heat sources 3000 per production well 3002 within theformation.

[1535] The total number of heat sources inside unit cell 3012 may bedetermined by the following method:

[1536] (a) 4 heat sources 3000 a inside unit cell 3012 are counted asone heat source each;

[1537] (b) 8 heat sources 3000 b on midlines 3006 are counted asone-half heat source each; and

[1538] (c) 4 heat sources 3000 c at vertices 3008 are counted asone-quarter heat source each.

[1539] The total number of heat sources is determined from adding theheat sources counted by, (a) 4, (b) 8/2=4, and (c) 4/4=1, for a totalnumber of 9 heat sources 3000 in unit cell 3012. Therefore, a ratio ofheat sources 3000 to production wells 3002 is determined as 9:1 for thepattern illustrated in FIG. 169.

[1540]FIG. 170 illustrates an example of another pattern of heat sources3000 and production wells 3002. Midlines 3006 are formed equidistantfrom two production wells 3002, and perpendicular to a line connectingsuch production wells. Unit cell 3014 is determined by intersection ofmidlines 3006 at vertices 3008. Twelve heat sources 3000 are counted inunit cell 3014, of which six are whole sources of heat, and six areone-third sources of heat (with the other two-thirds of heat from suchsix wells going to other patterns). Thus, a ratio of heat sources 3000to production wells 3002 is determined as 8:1 for the patternillustrated in FIG. 170.

[1541]FIG. 171 illustrates an embodiment of triangular pattern 3100 ofheat sources 3102. FIG. 172 illustrates an embodiment of square pattern3101 of heat sources 3103. FIG. 173 illustrates an embodiment ofhexagonal pattern 3104 of heat sources 3106. FIG. 174 illustrates anembodiment of 12:1 pattern 3105 of heat sources 3107. A temperaturedistribution for all patterns may be determined by an analytical method.The analytical method may be simplified by analyzing only temperaturefields within “confined” patterns (e.g., hexagons), i.e., completelysurrounded by others. In addition, the temperature field may beestimated to be a superposition of analytical solutions corresponding toa single heat source.

[1542]FIG. 175 illustrates a schematic diagram of an embodiment ofsurface facilities 2800 that may treat a formation fluid. The formationfluid may be produced though a production well. As shown in FIG. 175,surface facilities 2800 may be coupled to separator 2802. Separator mayreceive formation fluid produced from a relatively permeable formationduring an in situ conversion process. Separator 2802 may separate theformation fluid into gas stream 2804, liquid hydrocarbon condensatestream 2806, and water stream 2808.

[1543] Water stream 2808 may flow from separator 2802 to a portion of aformation, to a containment system, or to a processing unit. Forexample, water stream 2808 may flow from separator 2802 to an ammoniaproduction unit. Ammonia produced in the ammonia production unit mayflow to an ammonium sulfate unit. The ammonium sulfate unit may combinethe ammonia with H₂SO₄ or SO₂/SO₃ to produce ammonium sulfate. Inaddition, ammonia produced in the ammonia production unit may flow to aurea production unit. The urea production unit may combine carbondioxide with the ammonia to produce urea.

[1544] Gas stream 2804 may flow through a conduit from separator 2802 togas treatment unit 2810. The gas treatment unit may separate variouscomponents of gas stream 2804. For example, the gas treatment unit mayseparate gas stream 2804 into carbon dioxide stream 2812, hydrogensulfide stream 2814, hydrogen stream 2816, and stream 2818 that mayinclude, but is not limited to, methane, ethane, propane, butanes(including n-butane or isobutane), pentane, ethene, propene, butene,pentene, water, or combinations thereof.

[1545] The carbon dioxide stream may flow through a conduit to aformation, to a containment system, to a disposal unit, and/or toanother processing unit. In addition, the hydrogen sulfide stream mayalso flow through a conduit to a containment system and/or to anotherprocessing unit. For example, the hydrogen sulfide stream may beconverted into elemental sulfur in a Claus process unit. The gastreatment unit may separate gas stream 2804 into stream 2819. Stream2819 may include heavier hydrocarbon components from gas stream 2804.Heavier hydrocarbon components may include, for example, hydrocarbonshaving a carbon number of greater than about 5. Heavier hydrocarboncomponents in stream 2819 may be provided to liquid hydrocarboncondensate stream 2806.

[1546] Surface facilities 2800 may also include processing unit 2821.Processing unit 2821 may separate stream 2818 into a number of streams.Each of the streams may be rich in a predetermined component or apredetermined number of compounds. For example, processing unit 2821 mayseparate stream 2818 into first portion 2820 of stream 2818, secondportion 2823 of stream 2818, third portion 2825 of stream 2818, andfourth portion 2831 of stream 2818. First portion 2820 of stream 2818may include lighter hydrocarbon components such as methane and ethane.First portion 2820 of stream 2818 may flow from gas treatment unit 2810to power generation unit 2822.

[1547] Power generation unit 2822 may extract useable energy from thefirst portion of stream 2818. For example, stream 2818 may be producedunder pressure. Power generation unit 2822 may include a turbine thatgenerates electricity from the first portion of stream 2818. The powergeneration unit may also include, for example, a molten carbonate fuelcell, a solid oxide fuel cell, or other type of fuel cell. The extracteduseable energy may be provided to user 2824. User 2824 may include, forexample, surface facilities 2800, a heat source disposed within aformation, and/or a consumer of useable energy.

[1548] Second portion 2823 of stream 2818 may also include lighthydrocarbon components. For example, second portion 2823 of stream 2818may include, but is not limited to, methane and ethane. Second portion2823 of stream 2818 may be provided to natural gas pipeline 2827.Alternatively, second portion 2823 of stream 2818 may be provided to alocal market. The local market may be a consumer market or a commercialmarket. Second portion 2823 of stream 2818 may be used as an end productor an intermediate product depending on, for example, a composition ofthe light hydrocarbon components.

[1549] Third portion 2825 of stream 2818 may include liquefied petroleumgas (“LPG”). Major constituents of LPG may include hydrocarbonscontaining three or four carbon atoms such as propane and butane. Butanemay include n-butane or isobutane. LPG may also include relatively smallconcentrations of other hydrocarbons, such as ethene, propene, butene,and pentene. Some LPG may also include additional components. LPG may bea gas at atmospheric pressure and normal ambient temperatures. LPG maybe liquefied, however, when moderate pressure is applied or when thetemperature is sufficiently reduced. When such moderate pressure isreleased, LPG gas may have about 250 times a volume of LPG liquid.Therefore, large amounts of energy may be stored and transportedcompactly as LPG.

[1550] Third portion 2825 of stream 2818 may be provided to local market2829. The local market may include a consumer market or a commercialmarket. Third portion 2825 of stream 2818 may be used as an end productor an intermediate product. LPG may be used in applications, such asfood processing, aerosol propellants, and automotive fuel. LPG may beprovided in for standard heating and cooking purposes as commercialpropane and/or commercial butane. Propane may be more versatile forgeneral use than butane because propane has a lower boiling point thanbutane.

[1551] Fourth portion 2831 of stream 2818 may flow from the gastreatment unit to hydrogen manufacturing unit 2828. Hydrogen-rich stream2830 is shown exiting hydrogen manufacturing unit 2828. Examples ofhydrogen manufacturing unit 2828 may include a steam reformer and acatalytic flameless distributed combustor with a hydrogen separationmembrane.

[1552]FIG. 176 illustrates an embodiment of a catalytic flamelessdistributed combustor. An example of a catalytic flameless distributedcombustor with a hydrogen separation membrane is illustrated in U.S.Patent Application No. 60/273,354, filed on Mar. 5, 2001, which isincorporated by reference as if fully set forth herein. A catalyticflameless distributed combustor may include fuel line 2850, oxidant line2852, catalyst 2854, and membrane 2856. Fourth portion 2831 of stream2818 (shown in FIG. 175) may be provided to hydrogen manufacturing unit2828 as fuel 2858. Fuel 2858 within fuel line 2850 may mix withinreaction volume in annular space 2859 between the fuel line and theoxidant line. Reaction of the fuel with the oxidant in the presence ofcatalyst 2854 may produce reaction products that include H₂. Membrane2856 may allow a portion of the generated H₂ to pass into annular space2860 between outer wall 2862 of oxidant line 2852 and membrane 2856.Excess fuel passing out of fuel line 2850 may be circulated back toentrance of hydrogen manufacturing unit 2828. Combustion productsleaving oxidant line 2852 may include carbon dioxide and other reactionsproducts as well as some fuel and oxidant. The fuel and oxidant may beseparated and recirculated back to the hydrogen manufacturing unit.Carbon dioxide may be separated from the exit stream. The carbon dioxidemay be sequestered within a portion of a formation or used for analternate purpose.

[1553] Fuel line 2850 may be concentrically positioned within oxidantline 2852. Critical flow orifices 2863 within fuel line 2850 may allowfuel to enter into a reaction volume in annular space 2859 between thefuel line and oxidant line 2852. The fuel line may carry a mixture ofwater and vaporized hydrocarbons such as, but not limited to, methane,ethane, propane, butane, methanol, ethanol, or combinations thereof. Theoxidant line may carry an oxidant such as, but not limited to, air,oxygen enriched air, oxygen, hydrogen peroxide, or combinations thereof.

[1554] Catalyst 2854 may be located in the reaction volume to allowreactions that produce H₂ to proceed at relatively low temperatures.Without a catalyst and without membrane separation of H₂, a steamreformation reaction may need to be conducted in a series of reactorswith temperatures for a shift reaction occurring in excess of 980° C.With a catalyst and with separation of H₂ from the reaction stream, thereaction may occur at temperatures within a range from about 300° C. toabout 600° C., or within a range from about 400° C. to about 500° C.Catalyst 2854 may be any steam reforming catalyst. In selectedembodiments, catalyst 2854 is a group VIII transition metal, such asnickel. The catalyst may be supported on porous substrate 2864. Thesubstrate may include group III or group IV elements, such as, but notlimited to, aluminum, silicon, titanium, or zirconium. In an embodiment,the substrate is alumina (Al₂O₃).

[1555] Membrane 2856 may remove H₂ from a reaction stream within areaction volume of a hydrogen manufacturing unit 2828. When H₂ isremoved from the reaction stream, reactions within the reaction volumemay generate additional H₂. A vacuum may draw H₂ from an annular regionbetween membrane 2856 and outer wall 2862 of oxidant line 2852.Alternately, H₂ may be removed from the annular region in a carrier gas.Membrane 2856 may separate H₂ from other components within the reactionstream. The other components may include, but are not limited to,reaction products, fuel, water, and hydrogen sulfide. The membrane maybe a hydrogen-permeable and hydrogen selective material such as, but notlimited to, a ceramic, carbon, metal, or combination thereof. Themembrane may include, but is not limited to, metals of group VIII, V,III, or I such as palladium, platinum, nickel, silver, tantalum,vanadium, yttrium, and/or niobium. The membrane may be supported on aporous substrate such as alumina. The support may separate the membrane2856 from catalyst 2854. The separation distance and insulationproperties of the support may help to maintain the membrane within adesired temperature range.

[1556] Hydrogen manufacturing unit 2828 of the surface facilitiesembodiment depicted in FIG. 175 may produce hydrogen-rich stream 2830from the second portion stream 2818. Hydrogen-rich stream 2830 may flowinto hydrogen stream 2816 to form stream 2832. Stream 2832 may include alarger volume of hydrogen than either hydrogen-rich stream 2830 orhydrogen stream 2816.

[1557] Hydrocarbon condensate stream 2806 may flow through a conduitfrom wellhead 2803 to hydrotreating unit 2834. Hydrotreating unit 2834may hydrogenate hydrocarbon condensate stream 2806 to form hydrogenatedhydrocarbon condensate stream 2836. The hydrotreater may upgrade andswell the hydrocarbon condensate. Surface facilities 2800 may providestream 2832 (which includes a relatively high concentration of hydrogen)to hydrotreating unit 2834. H₂ in stream 2832 may hydrogenate a doublebond of the hydrocarbon condensate, thereby reducing a potential forpolymerization of the hydrocarbon condensate. In addition, hydrogen mayalso neutralize radicals in the hydrocarbon condensate. The hydrogenatedhydrocarbon condensate may include relatively short chain hydrocarbonfluids. Furthermore, hydrotreating unit 2834 may reduce sulfur,nitrogen, and aromatic hydrocarbons in hydrocarbon condensate stream2806. Hydrotreating unit 2834 may be a deep hydrotreating unit or a mildhydrotreating unit. An appropriate hydrotreating unit may vary dependingon, for example, a composition of stream 2832, a composition of thehydrocarbon condensate stream, and/or a selected composition of thehydrogenated hydrocarbon condensate stream.

[1558] Hydrogenated hydrocarbon condensate stream 2836 may flow fromhydrotreating unit 2834 to transportation unit 2838. Transportation unit2838 may collect a volume of the hydrogenated hydrocarbon condensateand/or to transport the hydrogenated hydrocarbon condensate to marketcenter 2840. Market center 2840 may include, but is not limited to, aconsumer marketplace or a commercial marketplace. A commercialmarketplace may include a refinery. The hydrogenated hydrocarboncondensate may be used as an end product or an intermediate product.

[1559] Alternatively, hydrogenated hydrocarbon condensate stream 2836may flow to a splitter or an ethene production unit. The splitter mayseparate the hydrogenated hydrocarbon condensate stream into ahydrocarbon stream including components having carbon numbers of 5 or 6,a naphtha stream, a kerosene stream, and/or a diesel stream. Selectedstreams exiting the splitter may be fed to the ethene production unit.In addition, the hydrocarbon condensate stream and the hydrogenatedhydrocarbon condensate stream may be fed to the ethene production unit.Ethene produced by the ethene production unit may be fed to apetrochemical complex to produce base and industrial chemicals andpolymers. Alternatively, the streams exiting the splitter may be fed toa hydrogen conversion unit. A recycle stream may flow from the hydrogenconversion unit to the splitter. The hydrocarbon stream exiting thesplitter and the naphtha stream may be fed to a mogas production unit.The kerosene stream and the diesel stream may be distributed as product.

[1560]FIG. 177 illustrates an embodiment of an additional processingunit that may be included in surface facilities 2800, such as thefacilities depicted in FIG. 175. Air 2903 may be fed to air separationunit 2900. Air separation unit 2900 may generate nitrogen stream 2902and oxygen stream 2905. Oxygen stream 2905 and steam 2904 may beinjected into exhausted coal resource 2906 to generate synthesis gas2907. Produced synthesis gas 2907 may be provided to Shell MiddleDistillates process unit 2910 that produces middle distillates 2912. Inaddition, produced synthesis gas 2907 may be provided to catalyticmethanation process unit 2914 that produces natural gas 2916. Producedsynthesis gas 2907 may also be provided to methanol production unit 2918to produce methanol 2920. Produced synthesis gas 2907 may be provided toprocess unit 2922 for production of ammonia and/or urea 2924. Synthesisgas may be used as a fuel for fuel cell 2926 that produces electricity2928. Synthesis gas 2907 may also be routed to power generation unit2930, such as a turbine or combustor, to produce electricity 2932.

[1561] The comparisons of patterns of heat sources were evaluated forthe same heater well density and the same heating input regime. Forexample, a number of heat sources per unit area in a triangular patternis the same as the number of heat sources per unit area in the 10 mhexagonal pattern if the space between heat sources is increased toabout 12.2 m in the triangular pattern. The equivalent spacing for asquare pattern would be 11.3 m, while the equivalent spacing for a 12:1pattern would be 15.7 m.

[1562]FIG. 178 illustrates temperature profile 3110 after three years ofheating for a triangular pattern with a 12.2 m spacing in a typical oilshale. FIG. 171 depicts an embodiment of a triangular pattern.Temperature profile 3110 is a three-dimensional plot of temperatureversus a location within a triangular pattern. FIG. 179 illustratestemperature profile 3108 after three years of heating for a squarepattern with 11.3 m spacing in a typical oil shale. Temperature profile3108 is a three-dimensional plot of temperature versus a location withina square pattern. FIG. 172 depicts an embodiment of a square pattern.FIG. 180 illustrates temperature profile 3109 after three years ofheating for a hexagonal pattern with 10.0 m spacing in a typical oilshale. Temperature profile 3109 is a three-dimensional plot oftemperature versus a location within a hexagonal pattern. FIG. 173depicts an embodiment of a hexagonal pattern.

[1563] As shown in a comparison of FIGS. 178, 179, and 180, atemperature profile of the triangular pattern is more uniform than atemperature profile of the square or hexagonal pattern. For example, aminimum temperature of the square pattern is approximately 280° C., anda minimum temperature of the hexagonal pattern is approximately 250° C.In contrast, a minimum temperature of the triangular pattern isapproximately 300° C. Therefore, a temperature variation within thetriangular pattern after 3 years of heating is 20° C. less than atemperature variation within the square pattern and 50° C. less than atemperature variation within the hexagonal pattern. For a chemicalprocess, where reaction rate is proportional to an exponent oftemperature, a 20° C. difference may have a substantial effect onproducts being produced in a pyrolysis zone.

[1564]FIG. 181 illustrates a comparison plot between the average patterntemperature (in degrees Celsius) and temperatures at the coldest spotsfor each pattern as a function of time (in years). The coldest spot foreach pattern is located at a pattern center (centroid). As shown in FIG.171, the coldest spot of a triangular pattern is point 3118, while point3117 is the coldest spot of a square pattern, as shown in FIG. 172. Asshown in FIG. 173, the coldest spot of a hexagonal pattern is point3114, while point 3115 is the coldest spot of a 12:1 pattern, as shownin FIG. 174. The difference between an average pattern temperature andtemperature of the coldest spot represents how uniform the temperaturedistribution for a given pattern is. The more uniform the heating, thebetter the product quality that may be made in the formation. The largerthe volume fraction of resource that is overheated, the greater theamount of undesirable product tends to be made.

[1565] As shown in FIG. 181, the difference between average temperature3120 of a pattern and temperature of the coldest spot is less fortriangular pattern 3118 than for square pattern 3117, hexagonal pattern3114, or 12:1 pattern 3115. Again, there is a substantial differencebetween triangular and hexagonal patterns.

[1566] Another way to assess the uniformity of temperature distributionis to compare temperatures of the coldest spot of a pattern with a pointlocated at the center of a side of a pattern midway between heaters. Asshown in FIG. 173, point 3112 is located at the center of a side of thehexagonal pattern midway between heaters. As shown in FIG. 171, point3116 is located at the center of a side of a triangular pattern midwaybetween heaters. Point 3119 is located at the center of a side of thesquare pattern midway between heaters, as shown in FIG. 172.

[1567]FIG. 182 illustrates a comparison plot between average patterntemperature 3120 (in degrees Celsius), temperatures at coldest spot 3118for triangular patterns, coldest spot 3114 for hexagonal patterns, point3116 located at the center of a side of triangular pattern midwaybetween heaters, and point 3112 located at the center of a side ofhexagonal pattern midway between heaters, as a function of time (inyears). FIG. 183 illustrates a comparison plot between average patterntemperature 3120 (in degrees Celsius), temperatures at coldest spot 3117and point 3119 located at the center of a side of a pattern midwaybetween heaters, as a function of time (in years), for a square pattern.

[1568] As shown in a comparison of FIGS. 182 and 183, for each pattern,a temperature at a center of a side midway between heaters is higherthan a temperature at a center of the pattern. A difference between atemperature at a center of a side midway between heaters and a center ofthe hexagonal pattern increases substantially during the first year ofheating, and stays relatively constant afterward. A difference between atemperature at an outer lateral boundary and a center of the triangularpattern, however, is negligible. Therefore, a temperature distributionin a triangular pattern is more uniform than a temperature distributionin a hexagonal pattern. A square pattern also provides more uniformtemperature distribution than a hexagonal pattern, however, it is stillless uniform than a temperature distribution in a triangular pattern.

[1569] A triangular pattern of heat sources may have, for example, ashorter total process time than a square, hexagonal, or 12:1 pattern ofheat sources for the same heater well density. A total process time mayinclude a time required for an average temperature of a heated portionof a formation to reach a target temperature and a time required for atemperature at a coldest spot within the heated portion to reach thetarget temperature. For example, heat may be provided to the portion ofthe formation until an average temperature of the heated portion reachesthe target temperature. After the average temperature of the heatedportion reaches the target temperature, an energy supply to the heatsources may be reduced such that less or minimal heat may be provided tothe heated portion. An example of a target temperature may beapproximately 340° C. The target temperature, however, may varydepending on, for example, formation composition and/or formationconditions such as pressure.

[1570]FIG. 184 illustrates a comparison plot between the average patterntemperature and temperatures at the coldest spots for each pattern, as afunction of time when heaters are turned off after the averagetemperature reaches a target value. As shown in FIG. 184, averagetemperature 3120 of the formation reaches a target temperature (about340° C.) in approximately 3 years. As shown in FIG. 184, a temperatureat the coldest point within the triangular pattern 3118 reaches thetarget temperature (about 340° C.) about 0.8 years later. A totalprocess time for such a triangular pattern is about 3.8 years when theheat input is discontinued when the target average temperature isreached. As shown in FIG. 184, a temperature at the coldest point withinthe triangular pattern reaches the target temperature (about 340° C.)before a temperature at coldest point within the square pattern 3117 ora temperature at the coldest point within the hexagonal pattern 3114reaches the target temperature. A temperature at the coldest pointwithin the hexagonal pattern, however, reaches the target temperatureafter an additional time of about 2 years when the heaters are turnedoff upon reaching the target average temperature. Therefore, a totalprocess time for a hexagonal pattern is about 5.0 years. A total processtime for heating a portion of a formation with a triangular pattern is1.2 years less (approximately 25% less) than a total process time forheating a portion of a formation with a hexagonal pattern. In anembodiment, the power to the heaters may be reduced or turned off whenthe average temperature of the pattern reaches a target level. Thisprevents overheating the resource, which wastes energy and produceslower product quality. The triangular pattern has the most uniformtemperatures and the least overheating. Although a capital cost of sucha triangular pattern may be approximately the same as a capital cost ofthe hexagonal pattern, the triangular pattern may accelerate oilproduction and require a shorter total process time.

[1571] A triangular pattern may be more economical than a hexagonalpattern. A spacing of heat sources in a triangular pattern that willhave about the same process time as a hexagonal pattern having about a10.0 m space between heat sources may be equal to approximately 14.3 m.The triangular pattern may include about 26% less heat sources than theequivalent hexagonal pattern. Using the triangular pattern may allow forlower capital cost (i.e., there are fewer heat sources and productionwells) and lower operating costs (i.e., there are fewer heat sources andproduction wells to power and operate).

[1572]FIG. 56 depicts an embodiment of a natural distributed combustor.In one experiment, the embodiment schematically shown in FIG. 56 wasused to heat high volatile bituminous C coal in situ. A portion of aformation was heated with electrical resistance heaters and/or a naturaldistributed combustor. Thermocouples were located every 2 feet along thelength of the natural distributed combustor (along conduit 532schematically shown in FIG. 56). The coal was first heated withelectrical resistance heaters until pyrolysis was complete near thewell. FIG. 185 depicts square data points measured during electricalresistance heating at various depths in the coal after the temperatureprofile had stabilized (the coal seam was about 16 feet thick startingat about 28 feet of depth). At this point heat energy was being suppliedat about 300 watts per foot. Air was subsequently injected via conduit532 at gradually increasing rates, and electric power supplied to theelectrical resistance heaters was decreased. Combustion products wereremoved from the reaction volume through an annular space betweenconduit 532 and a well casing. The power supplied to the electricalresistance heaters was decreased at a rate that would approximatelyoffset heating provided by the combustion of the coal adjacent toconduit 532. Air input was increased and power input was decreased overa period of about 2 hours until no electric power was being supplied.

[1573] Diamond data points of FIG. 185 depict temperature as a functionof depth for natural distributed combustion heating (without anyelectrical resistance heating) in the coal after the temperature profilehad substantially stabilized. As can be seen in FIG. 185, the naturaldistributed combustion heating provided a temperature profile that iscomparable to the electrical resistance temperature profile (representedby square data points). This experiment demonstrated that naturaldistributed combustors may provide formation heating that is comparableto the formation heating provided by electrical resistance heaters. Thisexperiment was repeated at different temperatures and in two otherwells, all with similar results.

[1574] Numerical calculations have been made for a natural distributedcombustor system that heats a relatively permeable formation. Acommercially available program called PRO-II (Simulation Sciences Inc.,Brea, Calif.) was used to make example calculations based on a conduitof diameter 6.03 cm with a wall thickness of 0.39 cm. The conduit wasdisposed in an opening in the formation with a diameter of 14.4 cm. Theconduit had critical flow orifices of 1.27 mm diameter spaced 183 cmapart. The conduit heated a formation of 91.4 m thickness. A flow rateof air was 1.70 standard cubic meters per minute through the criticalflow orifices. Pressure of air at the inlet of the conduit was 7 barsabsolute. Exhaust gases had a pressure of 3.3 bars absolute. A heatingoutput of 1066 watts per meter was used. A temperature in the openingwas set at 760° C. The calculations determined a minimal pressure dropwithin the conduit of about 0.023 bars. The pressure drop within theopening was less than 0.0013 bars.

[1575]FIG. 186 illustrates extension (in meters) of a reaction zonewithin a coal formation over time (in years) according to the parametersset in the calculations. The width of the reaction zone increases withtime due to oxidation of carbon adjacent to the conduit.

[1576] Numerical calculations have been made for heat transfer using aconductor-in-conduit heater. Calculations were made for a conductorhaving a diameter of about 1 inch (2.54 cm) disposed in a conduit havinga diameter of about 3 inches (7.62 cm). The conductor-in-conduit heaterwas disposed in an opening of a carbon containing formation having adiameter of about 6 inches (15.24 cm). An emissivity of the carboncontaining formation was maintained at a value of 0.9, which is expectedfor geological materials. The conductor and the conduit were givenalternate emissivity values of high emissivity (0.86), which is commonfor oxidized metal surfaces, and low emissivity (0.1), which is forpolished and/or un-oxidized metal surfaces. The conduit was filled witheither air or helium. Helium is known to be a more thermally conductivegas than air. The space between the conduit and the opening was filledwith a gas mixture of methane, carbon dioxide, and hydrogen gases. Twodifferent gas mixtures were used. The first gas mixture had molefractions of 0.5 for methane, 0.3 for carbon dioxide, and 0.2 forhydrogen. The second gas mixture had mole fractions of 0.2 for methane,0.2 for carbon dioxide, and 0.6 for hydrogen.

[1577]FIG. 187 illustrates a calculated ratio of conductive heattransfer to radiative heat transfer versus a temperature of a face ofthe relatively permeable formation in the opening for an air filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values, thermal conductivities,dimensions of the conductor, conduit, and opening, and the temperatureof the conduit. Line 3204 is calculated for the low emissivity value(0.1). Line 3206 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit provides for a higherratio of conductive to radiative heat transfer to the formation. Thedecrease in the ratio with an increase in temperature may be due to areduction of conductive heat transfer with increasing temperature. Asthe temperature on the face of the formation increases, a temperaturedifference between the face and the heater is reduced, thus reducing atemperature gradient that drives conductive heat transfer.

[1578]FIG. 188 illustrates a calculated ratio of conductive heattransfer to radiative heat transfer versus a temperature at a face ofthe carbon containing formation in the opening for a helium filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values; thermal conductivities;dimensions of the conductor, conduit, and opening; and the temperatureof the conduit. Line 3208 is calculated for the low emissivity value(0.1). Line 3210 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit again provides for ahigher ratio of conductive to radiative heat transfer to the formation.The use of helium instead of air in the conduit significantly increasesthe ratio of conductive heat transfer to radiative heat transfer. Thismay be due to a thermal conductivity of helium being about 5.2 to about5.3 times greater than a thermal conductivity of air.

[1579]FIG. 189 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for a helium filled conduit and a high emissivity of 0.86. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 3212 and conduit temperature3214 were calculated from opening temperature 3216 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases(helium, methane, carbon dioxide, and hydrogen). It may be seen from theplots of temperatures of the conductor, conduit, and opening for theconduit filled with helium, that at higher temperatures approaching 871°C., the temperatures of the conductor, conduit, and opening begin toequilibrate.

[1580]FIG. 190 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for an air filled conduit and a high emissivity of 0.86. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 3212 and conduit temperature3214 were calculated from opening temperature 3216 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases (air,methane, carbon dioxide, and hydrogen). It may be seen from the plots oftemperatures of the conductor, conduit, and opening for the conduitfilled with air, that at higher temperatures approaching 871° C., thetemperatures of the conductor, conduit, and opening begin toequilibrate, as seen for the helium filled conduit with high emissivity.

[1581]FIG. 191 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for a helium filled conduit and a low emissivity of 0.1. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 3212 and conduit temperature3214 were calculated from opening temperature 3216 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases(helium, methane, carbon dioxide, and hydrogen). It may be seen from theplots of temperatures of the conductor, conduit, and opening for theconduit filled with helium, that at higher temperatures approaching 871°C., the temperatures of the conductor, conduit, and opening do not beginto equilibrate as seen for the high emissivity example shown in FIG.189. In addition, higher temperatures in the conductor and the conduitare needed to achieve an opening and face temperature of 871° C. Thus,increasing an emissivity of the conductor and the conduit may beadvantageous in reducing operating temperatures needed to produce adesired temperature in a carbon containing formation. Such reducedoperating temperatures may allow for the use of less expensive alloysfor metallic conduits.

[1582]FIG. 192 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for an air filled conduit and a low emissivity of 0.1. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 3212 and conduit temperature3214 were calculated from opening temperature 3216 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases (air,methane, carbon dioxide, and hydrogen). It may be seen from the plots oftemperatures of the conductor, conduit, and opening for the conduitfilled with helium, that at higher temperatures approaching 871° C., thetemperatures of the conductor, conduit, and opening do not begin toequilibrate as seen for the high emissivity example shown in FIG. 190.In addition, higher temperatures in the conductor and the conduit areneeded to achieve an opening and face temperature of 871° C. Thus,increasing an emissivity of the conductor and the conduit may beadvantageous in reducing operating temperatures needed to produce adesired temperature in a carbon containing formation. Such reducedoperating temperatures may provide for a lesser metallurgical costassociated with materials that require less substantial temperatureresistance (e.g., a lower melting point).

[1583] Calculations were also made using the first mixture of gas havinga hydrogen mole fraction of 0.2. The calculations resulted insubstantially similar results to those for a hydrogen mole fraction of0.6.

[1584] It is believed that particle size will not substantially affectthe quality of condensable hydrocarbons produced from the treated heavyhydrocarbons, the quantity of condensable hydrocarbons produced from thetreated heavy hydrocarbons, the amount of gas produced from the treatedheavy hydrocarbons, the composition of the gas produced from the treatedheavy hydrocarbons, the time required to produce the condensablehydrocarbons and gas from the treated heavy hydrocarbons, or thetemperatures required to produce the condensable hydrocarbons and gasfrom the treated heavy hydrocarbons. It is believed that heavyhydrocarbons yield substantially the same results from treatment assmall particles of heavy hydrocarbons. As such, it is believed thatscale-up issues when treating heavy hydrocarbons will not substantiallyaffect treatment results.

[1585] Formation pressure may also have a significant effect on olefinproduction. A high formation pressure may result in the production ofsmall quantities of olefins. High pressure within a formation may resultin a high H₂ partial pressure within the formation. The high H₂ partialpressure may result in hydrogenation of the fluid within the formation.Hydrogenation may result in a reduction of olefins in a fluid producedfrom the formation. A high pressure and high H₂ partial pressure mayalso result in inhibition of aromatization of hydrocarbons within theformation. Aromatization may include formation of aromatic and cycliccompounds from alkanes and/or alkenes within a hydrocarbon mixture. Ifit is desirable to increase production of olefins from a formation, theolefin content of fluid produced from the formation may be increased byreducing pressure within the formation. The pressure may be reduced bydrawing off a larger quantity of formation fluid from a portion of theformation that is being produced. In some in situ conversion processembodiments, pressure within a formation adjacent to production wellsmay be reduced below atmospheric pressure (i.e., a vacuum may be drawnon the formation).

[1586]FIG. 196 depicts a cross-sectional representation of the in situexperimental field test system. As shown in FIG. 196, the experimentalfield test system included coal formation 3802 within the ground andgrout wall 3800. Coal formation 3802 dipped at an angle of approximately36° with a thickness of approximately 4.9 m. FIG. 195 illustrates alocation of heat sources 3804 a, 3804 b, 3804 c, production wells 3806a, 3806 b, and temperature observation wells 3808 a, 3808 b, 3808 c,3808 d used for the experimental field test system. The three heatsources were disposed in a triangular configuration. Production well3806 a was located proximate a center of the heat source pattern andequidistant from each of the heat sources. Second production well 3806 bwas located outside the heat source pattern and spaced equidistant fromthe two closest heat sources. Grout wall 3800 was formed around the heatsource pattern and the production wells. The grout wall was formed of 24pillars. Grout wall 3800 inhibited an influx of water into the portionduring the in situ experiment. In addition, grout wall 3800 inhibitedloss of generated hydrocarbon fluids to an unheated portion of theformation.

[1587] Temperatures were measured at various times during the experimentat each of four temperature observation wells 3808 a, 3808 b, 3808 c,3808 d located within and outside of the heat source pattern as shown inFIG. 195. The temperatures measured at each of the temperatureobservation wells are displayed in FIG. 197 as a function of time.Temperatures at observation wells 3808 a (3820), 3808 b (3822), and 3808c (3824) were relatively close to each other. A temperature attemperature observation well 3808 d (3826) was significantly colder.This temperature observation well was located outside of the heater welltriangle illustrated in FIG. 195. This data demonstrates that in zoneswhere there was little superposition of heat, temperatures weresignificantly lower. FIG. 198 illustrates temperature profiles measuredat heat sources 3804 a (3830), 3804 b (3832), and 3804 c (3834). Thetemperature profiles were relatively uniform at the heat sources.

[1588] In general, as temperature is increased, a greater amount ofadditional synthesis gas is produced for a given injected water rate.The reason is that at higher temperatures the reaction rate andconversion of water into synthesis gas increases.

[1589] Synthesis gas was produced in an in situ experiment from aportion of the coal formation shown in FIG. 196 and FIG. 195. In thisexperiment, heater wells were used to inject fluids into the formation.FIG. 199 is a plot of weight of volatiles (condensable anduncondensable) in kilograms as a function of cumulative energy contentof product in kilowatt hours from the in situ experimental field test.The figure illustrates the quantity and energy content of pyrolysisfluids and synthesis gas produced from the formation.

[1590]FIG. 200 is a plot of the volume of oil equivalent produced (m³)as a function of energy input into the coal formation (kW·h) from theexperimental field test. The volume of oil equivalent in cubic meterswas determined by converting the energy content of the volume ofproduced oil plus gas to a volume of oil with the same energy content.

[1591] The start of synthesis gas production, indicated by arrow 3912,was at an energy input of approximately 77,000 kW·h. The average coaltemperature in the pyrolysis region had been raised to 620° C. Becausethe average slope of the curve in FIG. 200 in the pyrolysis region isgreater than the average slope of the curve in the synthesis gas region,FIG. 200 illustrates that the amount of useable energy contained in theproduced synthesis gas is less than that contained in the pyrolysisfluids. Therefore, synthesis gas production is less energy efficientthan pyrolysis. There are two reasons for this result. First, the two H₂molecules produced in the synthesis gas reaction have a lower energycontent than low carbon number hydrocarbons produced in pyrolysis.Second, endothermic synthesis gas reactions consume energy.

[1592]FIG. 201 is a plot of the total synthesis gas production (m³/min)from the coal formation versus the total water inflow (kg/h) due toinjection into the formation from the experimental field test resultsfacility. Synthesis gas may be generated in a formation at a synthesisgas generating temperature before the injection of water or steam due tothe presence of natural water inflow into hot coal formation. Naturalwater may come from below the formation.

[1593] From FIG. 201, the maximum natural water inflow is approximately5 kg/h as indicated by arrow 3920. Arrows 3922, 3924, and 3926 representinjected water rates of about 2.7 kg/h, 5.4 kg/h, and 11 kg/h,respectively, into central well 3806 a of FIG. 195. Production ofsynthesis gas is at heater wells 3804 a, 3804 b, and 3804 c. FIG. 201shows that the synthesis gas production per unit volume of waterinjected decreases at arrow 3922 at approximately 2.7 kg/h of injectedwater or 7.7 kg/h of total water inflow. The reason for the decrease maybe that steam is flowing too fast through the coal seam to allow thereactions to approach equilibrium conditions.

[1594]FIG. 202 illustrates production rate of synthesis gas (m³/min) asa function of steam injection rate (kg/h) in a coal formation. Data 3930for a first run corresponds to injection at producer well 3806 a in FIG.195 and production of synthesis gas at heater wells 3804 a, 3804 b, and3804 c. Data 3932 for a second run corresponds to injection of steam atheater well 3804 c and production of additional gas at a production well3806 a. Data 3930 for the first run corresponds to the data shown inFIG. 201. As shown in FIG. 202, the injected water is in reactionequilibrium with the formation to about 2.7 kg/h of injected water. Thesecond run results in substantially the same amount of additionalsynthesis gas produced, shown by data 3932, as the first run to about1.2 kg/h of injected steam. At about 1.2 kg/h, data 3930 starts todeviate from equilibrium conditions because the residence time isinsufficient for the additional water to react with the coal. Astemperature is increased, a greater amount of additional synthesis gasis produced for a given injected water rate. The reason is that athigher temperatures the reaction rate and conversion of water intosynthesis gas increases.

[1595]FIG. 203 is a plot that illustrates the effect of methaneinjection into a heated coal formation in the experimental field test(all of the units in FIGS. 203-206 are in m³ per hour). FIG. 203demonstrates hydrocarbons added to the synthesis gas producing fluid arecracked within the formation. FIG. 195 illustrates the layout of theheater and production wells at the field test facility. Methane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperaturesat various wells were as follows: 3804 a (746° C.), 3804 b (746° C.),3804 c (767° C.), 3808 a (592° C.), 3808 b (573° C.), 3808 c (606° C.),and 3806 a (769° C.). When the methane contacted the formation, aportion of the methane cracked within the formation to produce H₂ andcoke. FIG. 203 shows that as the methane injection rate increased, theproduction of H₂ 3940 increased. This indicated that methane wascracking to form H₂. Methane production 3942 also increased, whichindicates that not all of the injected methane is cracked. The measuredcompositions of ethane, ethene, propane, and butane were negligible.

[1596]FIG. 204 is a plot that illustrates the effect of ethane injectioninto a heated coal formation in the experimental field test. Ethane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c in FIG. 195. The averagetemperatures at various wells were as follows: 3804 a (742° C.), 3804 b(750° C.), 3804 c (744° C.), 3808 a (611° C.), 3808 b (595° C.), 3808 c(626° C.), and 3806 a (818° C.). When ethane contacted the formation, itcracked to produce H₂, methane, ethene, and coke. FIG. 204 shows that asthe ethane injection rate increased, the production of H₂ 3950, methane3952, ethane 3954, and ethene 3956 increased. This indicates that ethaneis cracking to form H₂ and low molecular weight hydrocarbons. Theproduction rate of higher carbon number products (i.e., propane andpropylene) were unaffected by the injection of ethane.

[1597]FIG. 205 is a plot that illustrates the effect of propaneinjection into a heated coal formation in the experimental field test.Propane was injected into production wells 3806 a and 3806 b and fluidwas produced from heater wells 3804 a, 3804 b, and 3804 c. The averagetemperatures at various wells were as follows: 3804 a (737° C.), 3804 b(753° C.), 3804 c (726° C.), 3808 a (589° C.), 3808 b (573° C.), 3808 c(606° C.), and 3806 a (769° C.). When propane contacted the formation,it cracked to produce H₂, methane, ethane, ethene, propylene, and coke.FIG. 205 shows that as the propane injection rate increased, theproduction of H₂ 3960, methane 3962, ethane 3964, ethene 3966, propane3968, and propylene 3969 increased. This indicates that propane iscracking to form H₂ and lower molecular weight components.

[1598]FIG. 206 is a plot that illustrates the effect of butane injectioninto a heated coal formation in the experimental field test. Butane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperature atvarious wells were as follows: 3804 a (772° C.), 3804 b (764° C.), 3804c (753° C.), 3808 a (650° C.), 3808 b (591° C.), 3808 c (624° C.), and3806 a (830° C.). When butane contacted the formation, it cracked toproduce H₂, methane, ethane, ethene, propane, propylene, and coke. FIG.206 shows that as the butane injection rate increased, the production ofH₂ 3970, methane 3972, ethane 3974, ethene 3976, propane 3978, andpropylene 3979 increased. This indicates that butane is cracking to formH₂ and lower molecular weight components.

[1599]FIG. 207 is a plot of the composition of gas (in mole percent)produced from the heated coal formation versus time in days at theexperimental field test. The species compositions included methane 3980,H₂ 3982, carbon dioxide 3984, hydrogen sulfide 3986, and carbon monoxide3988. FIG. 207 shows a dramatic increase in H₂ concentration after about150 days, or when synthesis gas production began.

[1600]FIG. 208 is a plot of synthesis gas conversion versus time forsynthesis gas generation runs in the experimental field test performedon separate days. The temperature of the formation was about 600° C. Thedata demonstrates initial uncertainty in measurements in the oil/waterseparator. Synthesis gas conversion consistently approached a conversionof between about 40% and 50% after about 2 hours of synthesis gasproducing fluid injection.

[1601] TABLE 3 shows a composition of synthesis gas produced during arun of the in situ coal field experiment. TABLE 3 Component Mol % Wt %Methane 12.263 12.197 Ethane 0.281 0.525 Ethene 0.184 0.320 Acetylene0.000 0.000 Propane 0.017 0.046 Propylene 0.026 0.067 Propadiene 0.0010.004 Isobutane 0.001 0.004 n-Butane 0.000 0.001 1-Butene 0.001 0.003Isobutene 0.000 0.000 cis-2-Butene 0.005 0.018 trans-2-Butene 0.0010.003 1,3-Butadiene 0.001 0.005 Isopentane 0.001 0.002 n-Pentane 0.0000.002 Pentene-1 0.000 0.000 T-2-Pentene 0.000 0.000 2-Methyl-2-Butene0.000 0.000 C-2-Pentene 0.000 0.000 Hexanes 0.081 0.433 H₂ 51.247 6.405Carbon monoxide 11.556 20.067 Carbon dioxide 17.520 47.799 Nitrogen5.782 10.041 Oxygen 0.955 1.895 Hydrogen sulfide 0.077 0.163 Total100.000 100.000

[1602] The experiment was performed in batch oxidation mode at about620° C. The presence of nitrogen and oxygen is due to contamination ofthe sample with air. The mole percent of H₂, carbon monoxide, and carbondioxide, neglecting the composition of all other species, may bedetermined for the above data. For example, mole percent of H₂, carbonmonoxide, and carbon dioxide may be increased proportionally such thatthe mole percentages of the three components equals approximately 100%.The mole percent of H₂, carbon monoxide, and carbon dioxide, neglectingthe composition of all other species, were 63.8%, 14.4%, and 21.8%,respectively. The methane is believed to come primarily from thepyrolysis region outside the triangle of heaters. These values are insubstantial agreement with the equilibrium values shown in FIG. 209.

[1603]FIG. 209 is a plot of calculated equilibrium gas dry molefractions for a coal reaction with water. Methane reactions are notincluded. The fractions are representative of a synthesis gas producedfrom a relatively permeable formation and has been passed through acondenser to remove water from the produced gas. Equilibrium gas drymole fractions are shown in FIG. 209 for H₂ 4000, carbon monoxide 4002,and carbon dioxide 4004 as a function of temperature at a pressure of 2bars absolute. Liquid production from a formation substantially stops attemperatures of about 390° C. Gas produced at about 390° C. includesabout 67% H₂ and about 33% carbon dioxide. Carbon monoxide is present innegligible quantities below about 410° C. At temperatures of about 500°C., however, carbon monoxide is present in the produced gas inmeasurable quantities. For example, at 500° C., about 66.5% H₂, about32% carbon dioxide, and about 2.5% carbon monoxide are present. At 700°C., the produced gas includes about 57.5% H₂, about 15.5% carbondioxide, and about 27% carbon monoxide.

[1604]FIG. 210 is a plot of calculated equilibrium wet mole fractionsfor a coal reaction with water. Methane reactions are not included.Equilibrium wet mole fractions are shown for water 4006, H₂ 4008, carbonmonoxide 4010, and carbon dioxide 4012 as a function of temperature at apressure of 2 bars absolute. At 390° C., the produced gas includes about89% water, about 7% H₂, and about 4% carbon dioxide. At 500° C., theproduced gas includes about 66% water, about 22% H₂, about 11% carbondioxide, and about 1% carbon monoxide. At 700° C., the produced gasincludes about 18% water, about 47.5% H₂, about 12% carbon dioxide, andabout 22.5% carbon monoxide.

[1605]FIG. 209 and FIG. 210 illustrate that at the lower end of thetemperature range at which synthesis gas may be produced (i.e., about400° C.), equilibrium gas phase fractions may not favor production of H₂within and from a formation. As temperature increases, the equilibriumgas phase fractions increasingly favor the production of H₂. Forexample, as shown in FIG. 210, the gas phase equilibrium wet molefraction of H₂ increases from about 9% at 400° C. to about 39% at 610°C. and reaches 50% at about 800° C. FIG. 209 and FIG. 210 furtherillustrate that at temperatures greater than about 660° C., equilibriumgas phase fractions tend to favor production of carbon monoxide overcarbon dioxide.

[1606]FIG. 209 and FIG. 210 illustrate that as the temperature increasesfrom between about 400° C. to about 1000° C., the H₂ to carbon monoxideratio of produced synthesis gas may continuously decrease throughoutthis range. For example, as shown in FIG. 210, the equilibrium gas phaseH₂ to carbon monoxide ratio at 500° C., 660° C., and 1000° C. is about22:1, about 3:1, and about 1:1, respectively. FIG. 210 also indicatesthat produced synthesis gas at lower temperatures may have a largerquantity of water and carbon dioxide than at higher temperatures. As thetemperature increases, the overall percentage of carbon monoxide andhydrogen within the synthesis gas may increase.

[1607] Experimental adsorption data has demonstrated that carbon dioxidemay be stored in coal that has been pyrolyzed. FIG. 211 is a plot of thecumulative adsorbed methane and carbon dioxide in cubic meters permetric ton versus pressure in bars absolute at 25° C. on coal. The coalsample is sub-bituminous coal from Gillette, Wyo. Data sets 4402, 4403,4404, and 4405 are for carbon dioxide adsorption on a post treatmentcoal sample that has been pyrolyzed and has undergone synthesis gasgeneration. Data set 4406 is for adsorption on an unpyrolyzed coalsample from the same formation. Data set 4401 is adsorption of methaneat 25° C. Data sets 4402, 4403, 4404, and 4405 are adsorption of carbondioxide at 25° C., 50° C., 100° C., and 150° C., respectively. Data set4406 is adsorption of carbon dioxide at 25° C. on the unpyrolyzed coalsample. FIG. 211 shows that carbon dioxide at temperatures between 25°C. and 100° C. is more strongly adsorbed than methane at 25° C. in thepyrolyzed coal. FIG. 211 demonstrates that a carbon dioxide streampassed through post treatment coal tends to displace methane from thepost treatment coal.

[1608] Computer simulations have demonstrated that carbon dioxide may besequestered in both a deep coal formation and a post treatment coalformation. The Comet2™ Simulator (Advanced Resources International,Houston, Tex.) determined the amount of carbon dioxide that could besequestered in a San Juan Basin type deep coal formation and a posttreatment coal formation. The simulator also determined the amount ofmethane produced from the San Juan Basin type deep coal formation due tocarbon dioxide injection. The model employed for both the deep coalformation and the post treatment coal formation was a 1.3 km² area, witha repeating 5 spot well pattern. The 5 spot well pattern included fourinjection wells arranged in a square and one production well at thecenter of the square. The properties of the San Juan Basin and the posttreatment coal formations are shown in TABLE 4. Additional details ofsimulations of carbon dioxide sequestration in deep coal formations andcomparisons with field test results may be found in Pilot TestDemonstrates How Carbon Dioxide Enhances Coal Bed Methane Recovery,Lanny Schoeling and Michael McGovern, Petroleum Technology Digest,September 2000, p. 14-15. TABLE 4 Post treatment coal Deep CoalFormation (San formation (Post pyrolysis Juan Basin) process) CoalThickness (m) 9 9 Coal Depth (m) 990 460 Initial Pressure (bars abs.)114 2 Initial Temperature 25° C. 25° C. Permeability (md) 5.5 (horiz.),0 (vertical) 10,000 (horix.), 0 (vertical) Cleat porosity 0.2% 40%

[1609] The simulation model accounts for the matrix and dual porositynature of coal and post treatment coal. For example, coal and posttreatment coal are composed of matrix blocks. The spaces between theblocks are called “cleats.” Cleat porosity is a measure of availablespace for flow of fluids in the formation. The relative permeabilitiesof gases and water within the cleats required for the simulation werederived from field data from the San Juan coal. The same values forrelative permeabilities were used in the post treatment coal formationsimulations. Carbon dioxide and methane were assumed to have the samerelative permeability.

[1610] The cleat system of the deep coal formation was modeled asinitially saturated with water. Relative permeability data for carbondioxide and water demonstrate that high water saturation inhibitsabsorption of carbon dioxide within cleats. Therefore, water is removedfrom the formation before injecting carbon dioxide into the formation.

[1611] In addition, the gases within the cleats may adsorb in the coalmatrix. The matrix porosity is a measure of the space available forfluids to adsorb in the matrix. The matrix porosity and surface areawere taken into account with experimental mass transfer and isothermadsorption data for coal and post treatment coal. Therefore, it was notnecessary to specify a value of the matrix porosity and surface area inthe model. The pressure-volume-temperature (PVT) properties andviscosity required for the model were taken from literature data for thepure component gases.

[1612] The preferential adsorption of carbon dioxide over methane onpost treatment coal was incorporated into the model based onexperimental adsorption data. For example, FIG. 211 demonstrates thatcarbon dioxide has a significantly higher cumulative adsorption thanmethane over an entire range of pressures at a specified temperature.Once the carbon dioxide enters in the cleat system, methane diffuses outof and desorbs off the matrix. Similarly, carbon dioxide diffuses intoand adsorbs onto the matrix. In addition, FIG. 211 also shows carbondioxide may have a higher cumulative adsorption on a pyrolyzed coalsample than an unpyrolyzed coal sample.

[1613] The simulation modeled a sequestration process over a time periodof about 3700 days for the deep coal formation model. Removal of thewater in the coal formation was simulated by production from five wells.The production rate of water was about 40 m³/day for about the first 370days. The production rate of water decreased significantly after thefirst 370 days. It continued to decrease through the remainder of thesimulation run to about zero at the end. Carbon dioxide injection wasstarted at approximately 370 days at a flow rate of about 113,000standard (in this context “standard” means 1 atmosphere pressure and15.5° C.) m³/day. The injection rate of carbon dioxide was doubled toabout 226,000 standard m³/day at approximately 1440 days. The injectionrate remained at about 226,000 standard m³/day until the end of thesimulation run.

[1614]FIG. 212 illustrates the pressure at the wellhead of the injectionwells as a function of time during the simulation. The pressuredecreased from about 114 bars absolute to about 19 bars absolute overthe first 370 days. The decrease in the pressure was due to removal ofwater from the coal formation. Pressure then started to increasesubstantially as carbon dioxide injection started at 370 days. Thepressure reached a maximum of about 98 bars absolute. The pressure thenbegan to gradually decrease after 480 days. At about 1440 days, thepressure increased again to about 98 bars absolute due to the increasein the carbon dioxide injection rate. The pressure gradually increaseduntil about 3640 days. The pressure jumped at about 3640 days becausethe production well was closed off.

[1615]FIG. 213 illustrates the production rate of carbon dioxide 5060and methane 5070 as a function of time in the simulation. FIG. 213 showsthat carbon dioxide was produced at a rate between about 0-10,000 m³/dayduring approximately the first 2400 days. The production rate of carbondioxide was significantly below the injection rate. Therefore, thesimulation predicts that most of the injected carbon dioxide is beingsequestered in the coal formation. However, at about 2400 days, theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the coal formation.

[1616] In addition, FIG. 213 shows that methane was desorbing as carbondioxide was adsorbing in the coal formation. Between about 370-2400days, the methane production rate 5070 increased from about 60,000 toabout 115,000 standard m³/day. The increase in the methane productionrate between about 1440-2400 days was caused by the increase in carbondioxide injection rate at about 1440 days. The production rate ofmethane started to decrease after about 2400 days. This was due to thesaturation of the coal formation. The simulation predicted a 50%breakthrough at about 2700 days. “Breakthrough” is defined as the ratioof the flow rate of carbon dioxide to the total flow rate of the totalproduced gas times 100%. In addition, the simulation predicted about a90% breakthrough at about 3600 days.

[1617]FIG. 214 illustrates cumulative methane produced 5090 and thecumulative net carbon dioxide injected 5080 as a function of time duringthe simulation. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 214 shows that by the end of the simulated injection,about twice as much carbon dioxide was stored as methane produced. Inaddition, the methane production was about 0.24 billion standard m³ at50% carbon dioxide breakthrough. In addition, the carbon dioxidesequestration was about 0.39 billion standard m³ at 50% carbon dioxidebreakthrough. The methane production was about 0.26 billion standard m³at 90% carbon dioxide breakthrough. In addition, the carbon dioxidesequestration was about 0.46 billion standard m³ at 90% carbon dioxidebreakthrough.

[1618] TABLE 4 shows that the permeability and porosity of thesimulation in the post treatment coal formation were both significantlyhigher than in the deep coal formation prior to treatment. In addition,the initial pressure was much lower. The depth of the post treatmentcoal formation was shallower than the deep coal bed methane formation.The same relative permeability data and PVT data used for the deep coalformation were used for the coal formation simulation. The initial watersaturation for the post treatment coal formation was set at 70%. Waterwas present because it is used to cool the hot spent coal formation to25° C. The amount of methane initially stored in the post treatment coalis very low.

[1619] The simulation modeled a sequestration process over a time periodof about 3800 days for the post treatment coal formation model. Thesimulation modeled removal of water from the post treatment coalformation with production from five wells. During about the first 200days, the production rate of water was about 680,000 standard m³/day.From about 200-3300 days, the water production rate was between about210,000 to about 480,000 standard m³/day. Production rate of water wasnegligible after about 3300 days. Carbon dioxide injection was startedat approximately 370 days at a flow rate of about 113,000 standardm³/day. The injection rate of carbon dioxide was increased to about226,000 standard m³/day at approximately 1440 days. The injection rateremained at 226,000 standard m³/day until the end of the simulatedinjection.

[1620]FIG. 215 illustrates the pressure at the wellhead of the injectionwells as a function of time during the simulation of the post treatmentcoal formation model. The pressure was relatively constant up to about370 days. The pressure increased through most of the rest of thesimulation run up to about 36 bars absolute. The pressure rose steeplystarting at about 3300 days because the production well was closed off.

[1621]FIG. 216 illustrates the production rate of carbon dioxide as afunction of time in the simulation of the post treatment coal formationmodel. FIG. 216 shows that the production rate of carbon dioxide wasalmost negligible during approximately the first 2200 days. Therefore,the simulation predicts that nearly all of the injected carbon dioxideis being sequestered in the post treatment coal formation. However, atabout 2240 days, the produced carbon dioxide began to increase. Theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the post treatment coal formation.

[1622]FIG. 217 illustrates cumulative net carbon dioxide injected as afunction of time during the simulation in the post treatment coalformation model. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 217 shows that the simulation predicts a potential netsequestration of carbon dioxide of 0.56 Bm³. This value is greater thanthe value of 0.46 Bm³ at 90% carbon dioxide breakthrough in the deepcoal formation. However, comparison of FIG. 212 with FIG. 215 shows thatsequestration occurs at much lower pressures in the post treatment coalformation model. Therefore, less compression energy was required forsequestration in the post treatment coal formation.

[1623] The simulations show that large amounts of carbon dioxide may besequestered in both deep coal formations and in post treatment coalformations that have been cooled. Carbon dioxide may be sequestered inthe post treatment coal formation, in coal formations that have not beenpyrolyzed, and/or in both types of formations.

[1624] Low temperature pyrolysis experiments with tar sand wereconducted to determine a pyrolysis temperature zone and effects oftemperature in a heated portion on the quality of the producedpyrolyzation fluids. The tar sand was collected from the Athabasca tarsand region.

[1625]FIG. 193 depicts a retort and collection system used to conductthe experiments. Retort vessel 3314 was a pressure vessel of 316stainless steel for holding a material to be tested. The vessel andappropriate flow lines were wrapped with a 0.0254 m by 1.83 m electricheating tape. The wrapping provided substantially uniform heatingthroughout the retort system. The temperature was controlled bymeasuring a temperature of the retort vessel with a thermocouple andaltering the electrical input to the heating tape with a proportionalcontroller to approach a desired set point. Insulation surrounded theheating tape. The vessel sat on a 0.0508 m thick insulating block. Theheating tape extended past the bottom of the stainless steel vessel tocounteract heat loss from the bottom of the vessel.

[1626] A 0.00318 m stainless steel dip tube 3312 was inserted throughmesh screen 3310 and into the small dimple on the bottom of vessel 3314.Dip tube 3312 was slotted near an end to inhibit plugging of the diptube. Mesh screen 3310 was supported along the cylindrical wall of thevessel by a small ring having a thickness of about 0.00159 m. The smallring provides a space between an end of dip tube 3312 and a bottom ofretort vessel 3314 to inhibit solids from plugging the dip tube. Athermocouple was attached to the outside of the vessel to measure atemperature of the steel cylinder. The thermocouple was protected fromdirect heat of the heater by a layer of insulation. Air-operateddiaphragm type backpressure valve 3304 was provided for tests atelevated pressures. The products at atmospheric pressure passed intoconventional glass laboratory condenser 3320. Coolant disposed in thecondenser 3320 was chilled water having a temperature of about 1.7° C.The oil vapor and steam products condensed in the flow lines of thecondenser flowed into the graduated glass collection tube. A volume ofproduced oil and water was measured visually. Non-condensable gas flowedfrom condenser 3320 through gas bulb 3316. Gas bulb 3316 has a capacityof 500 cm³. In addition, gas bulb 3316 was originally filled withhelium. The valves on the bulb were two-way valves 3317 to provide easypurging of bulb 3316 and removal of non-condensable gases for analysis.Considering a sweep efficiency of the bulb, the bulb would be expectedto contain a composite sample of the previously produced 1 to 2 litersof gas. Standard gas analysis methods were used to determine the gascomposition. The gas exiting the bulb passed into collection vessel 3318that is in water 3322 in water bath 3324. Water bath 3324 was graduatedto provide an estimate of the volume of the produced gas over a time ofthe procedure (the water level changed, thereby indicating the amount ofgas produced). Collection vessel 3318 also included an inlet valve at abottom of the collection system under water and a septum at a top of thecollection system for transfer of gas samples to an analyzer.

[1627] At location 3300 one or more gases may be injected into thesystem shown in FIG. 193 to pressurize, maintain pressure, or sweepfluids in the system. Pressure gauge 3302 may be used to monitorpressure in the system. Heating/insulating material 3306 (e.g.,insulation or a temperature control bath) may be used to regulate and/ormaintain temperatures. Controller 3308 may be used to control heating ofvessel 3314.

[1628] A final volume of gas produced is not the volume of gas collectedover water because carbon dioxide and hydrogen sulfide are soluble inwater. Analysis of the water has shown that the gas collection systemover water removes about a half of the carbon dioxide produced in atypical experiment. The concentration of carbon dioxide in water affectsa concentration of the non-soluble gases collected over water. Inaddition, the volume of gas collected over water was found to vary fromabout one-half to two-thirds of the volume of gas produced.

[1629] The system was purged with about 5 to 10 pore volumes of heliumto remove all air and pressurized to about 20 bars absolute for 24 hoursto check for pressure leaks. Heating was then started slowly, takingabout 4 days to reach 260° C. After about 8 to 12 hours at 260° C., thetemperature was raised as specified by the schedule desired for theparticular test. Readings of temperature on the inside and outside ofthe vessel were recorded frequently to assure that the controller wasworking correctly.

[1630] Laboratory experiments were conducted on three tar samplescontained in their natural sand matrix. The three tar samples werecollected from the Athabasca tar sand region in western Canada. In eachcase, core material received from a well was mixed and then was split.One aliquot of the split core material was used in the retort, and thereplicate aliquot was saved for comparative analyses. Materials sampledincluded a tar sample within a sandstone matrix.

[1631] The heating rate for the runs was varied at 1° C./day, 5° C./day,and 10° C./day. The pressure condition was varied for the runs atpressures of 1 bar, 7.9 bars, and 28.6 bars. Run #78 was operated withno backpressure (about 1 bar absolute) and a heating rate of 1° C./day.Run #79 was operated with no backpressure (about 1 bar absolute) and aheating rate of 5° C./day. Run #81 was operated with no backpressure(about 1 bar absolute) and a heating rate of 10° C./day. Run #86 wasoperated at a pressure of 7.9 bars absolute and a heating rate of 10°C./day. Run #96 was operated at a pressure of 28.6 bars absolute and aheating rate of 10° C./day. In general, 0.5 to 1.5 kg initial weight ofthe sample was required to fill the available retort cells.

[1632] The internal temperature for the runs was raised from ambient to110° C., 200° C., 225° C. and 270° C., with 24 hours holding timebetween each temperature increase. Most of the moisture was removed fromthe samples during this heating. Beginning at 270° C., the temperaturewas increased by 1° C./day, 5° C./day, or 10° C./day until no furtherfluid was produced. The temperature was monitored and controlled duringthe heating of this stage.

[1633] Produced liquid was collected in graduated glass collectiontubes. Produced gas was collected in graduated glass collection bottles.Fluid volumes were read and recorded daily. Accuracy of the oil and gasvolume readings was within +/−0.6% and 2%, respectively. The experimentswere stopped when fluid production ceased. Power was turned off and morethan 12 hours was allowed for the retort to fall to room temperature.The pyrolyzed sample remains were unloaded, weighed, and stored insealed plastic cups. Fluid production and remaining rock material weresent out for analytical experimentation.

[1634] In addition, Dean Stark toluene solvent extraction was used toassay the amount of tar contained in the sample. In such an extractionprocedure, a solvent such as toluene or a toluene/xylene mixture ismixed with a sample and refluxed under a condenser using a receiver. Asthe refluxed sample condenses, two phases of the sample may separate asthey flow into the receiver. For example, tar may remain in the receiverwhile the solvent returns to the flask. Detailed procedures for DeanStark toluene solvent extraction are provided by the American Societyfor Testing and Materials. A 30 g sample from each depth was sent forDean Stark extraction analysis.

[1635] TABLE 5 illustrates the elemental analysis of initial tar and ofthe produced fluids for runs #81, #86, and #96. These data are all for aheating rate of 10° C./day. Only pressure was varied between the runs.TABLE 5 Run # P (bar) C (wt %) H (wt %) N (wt %) O (wt %) S (wt %) H/CN/C O/C S/C Initial Tar — 82.43 10.20 0.45 1.74 5.18 81 1 84.61 12.350.06 0.51 2.46 1.739 0.0006 0.0046 0.0109 86 7.9 85.09 12.47 0.05 0.501.89 1.746 0.0005 0.0044 0.0083 96 28.6 85.42 12.86 0.05 0.42 1.25 1.7940.0005 0.0037 0.0055

[1636] As illustrated in TABLE 5, pyrolysis of the tar sand decreasesnitrogen, sulfur, and oxygen weight percentages in a produced fluid.Increasing the pressure in the pyrolysis experiment appears to decreasethe nitrogen, sulfur, and oxygen weight percentage in the producedfluids. In addition, the weight percentage of hydrogen and the hydrogento carbon ratio increase with increasing pressure.

[1637] TABLE 6 illustrates NOISE (Nitric Oxide Ionization SpectrometryEvaluation) analysis data for runs #81, #86, and #96 and the initialtar. NOISE has been developed as a quantitative analysis of the weightpercentages of the main constituents in oil. The remaining weightpercentage (47.2%) in the initial tar may be found in the high molecularweight residue. TABLE 6 P Paraffins Cycloalkanes Phenols Mono-aromaticsRun # (bar) (wt %) (wt %) (wt %) (wt %) Di-aromatics (wt %)Tri-aromatics (wt %) Tetra-aromatics (wt %) Initial — 7.08 29.15 0 6.738.12 1.70 0.02 Tar 81 1 15.36 46.7 0.34 21.04 14.83 1.72 0.01 86 7.927.16 45.8 0.54 16.88 9.09 0.53 0 28.6 36.56 0.47 28.0 8.52 0 0

[1638] As illustrated in TABLE 6, pyrolyzation of tar sand produces aproduct fluid with a significantly higher weight percentage ofparaffins, cycloalkanes, and mono-aromatics than found in the initialtar sand. Increasing the pressure up to 7.9 bars absolute appears tosubstantially eliminate the production of tetra-aromatics. Furtherincreasing the pressure up to 28.6 bars absolute appears tosubstantially eliminate the production of tri-aromatics. An increase inthe pressure also appears to decrease production of di-aromatics.Increasing the pressure up to 28.6 bars absolute also appears tosignificantly increase production of mono-aromatics. This may be due toan increased hydrogen partial pressure at the higher pressure. Theincreased hydrogen partial pressure may reduce the number ofpoly-aromatic compounds and increase the number of mono-aromatics,paraffins, and/or cycloalkanes.

[1639]FIG. 218 illustrates plots of weight percentages of carboncompounds versus carbon number for initial tar 4703 and runs atpressures of 1 bar absolute 4704, 7.9 bars absolute 4705, and 28.6 barsabsolute 4706 with a heating rate of 10° C./day. From the plots ofinitial tar 4703 and a pressure of 1 bar absolute 4704, it can be seenthat pyrolysis shifts an average carbon number distribution torelatively lower carbon numbers. For example, a mean carbon number inthe carbon distribution of plot 4703 is about carbon number nineteen anda mean carbon number in the carbon distribution of plot 4704 is aboutcarbon number seventeen. Increasing the pressure to 7.9 bars absolute4705 further shifts the average carbon number distribution to even lowercarbon numbers. Increasing the pressure to 7.9 bars absolute 4705 shiftsthe mean carbon number in the carbon distribution to a carbon number ofabout thirteen. Increasing the pressure to 28.6 bars absolute 4706reduces the mean carbon number to about eleven. Increasing the pressureis believed to decrease the average carbon number distribution byincreasing a hydrogen partial pressure in the product fluid. Theincreased hydrogen partial pressure in the product fluid allowshydrogenation, dearomatization, and/or pyrolysis of large molecules toform smaller molecules. Increasing the pressure also increases a qualityof the produced fluid. For example, the API gravity of the fluidincreased from about 6° for the initial tar, to about 31° for a pressureof 1 bar absolute, to about 39° for a pressure of 7.9 bars absolute, toabout 45° for a pressure of 28.6 bars absolute.

[1640]FIG. 219 illustrates bar graphs of weight percentages of carboncompounds for various pyrolysis heating rates and pressures. Bar 4710illustrates weight percentages for pyrolysis with a heating rate of 1°C./day at a pressure of 1 bar absolute. Bar 4712 illustrates weightpercentages for pyrolysis with a heating rate of 5° C./day at a pressureof 1 bar absolute. Bar 4714 illustrates weight percentages for pyrolysiswith a heating rate of 10° C./day at a pressure of 1 bar absolute. Bar4716 illustrates weight percentages for pyrolysis with a heating rate of10° C./day at a pressure of 7.9 bars absolute. Weight percentages ofparaffins 4720, cycloalkanes 4722, mono-aromatics 4724, di-aromatics4726, and tri-aromatics 4728 are illustrated in the bars. The barsdemonstrate that a variation in the heating rate between 1° C./day to10° C./day does not significantly affect the composition of the productfluid. Increasing the pressure from 1 bar absolute to 7.9 bars absolute,however, affects a composition of the product fluid. Such an effect maybe characteristic of the effects described in FIG. 218 and TABLES 5 and6 above.

[1641]FIG. 194 illustrates a drum experimental apparatus. This apparatuswas used to test Athabasca tar sands. Electric heater 3404 and beadheater 3402 were used to uniformly heat contents of drum 3400.Insulation 3405 surrounds drum 3400. Contents of drum 3400 were heatedat a rate of about 2° C./day at various pressures. Measurements fromtemperature gauges 3406 were used to determine an average temperature indrum 3400. Pressure in the drum was monitored with pressure gauge 3408.Product fluids were removed from drum 3400 through conduit 3409.Temperature of the product fluids was monitored with temperature gauge3406 on conduit 3409. A pressure of the product fluids was monitoredwith pressure gauge 3408 on conduit 3409. Product fluids were separatedin separator 3410. Separator 3410 separated product fluids intocondensable and non-condensable products. Pressure in separator 3410 wasmonitored with pressure gauge 3408. Non-condensable product fluids wereremoved through conduit 3411. A composition of a portion ofnon-condensable product fluids removed from separator 3410 wasdetermined by gas analyzer 3412. A portion of condensable product fluidswas removed from separator 3410. Compositions of the portion ofcondensable product fluids collected were determined by externalanalysis methods. Temperature of the non-condensable fluids wasmonitored with temperature gauge 3406 on conduit 3411. A pressure of thenon-condensable fluids was monitored with pressure gauge 3408 on conduit3411. Flow of non-condensable fluids from separator 3410 was determinedby flow meter 3416. Fluids measured in flow meter 3416 were collectedand neutralized in carbon bed 3418. Gas samples were collected in gascontainer 3414.

[1642] Drum 3400 was filled with Athabasca tar sand and heated. Allexperiments were conducted using the system shown in FIG. 194. Vaporswere produced from the drum, cooled, separated into liquids and gases,and then analyzed. Two separate experiments were conducted, each usingtar sand from the same batch, but the drum pressure was maintained at 1bar absolute in one experiment (the low pressure experiment), and thedrum pressure was maintained at 6.9 bars absolute in the otherexperiment (the high pressure experiment). The drum pressures wereallowed to autogenously increase to the maintained pressure astemperatures were increased. In the low pressure experiment, the acidnumber of the treated tar sands was found to be 0.02 mg/gram KOH.

[1643]FIG. 220 illustrates mole % of hydrogen in the gases during theexperiment (i.e., when the drum temperature was increased at the rate of2° C./day). Line 4770 illustrates results obtained when the drumpressure was maintained at 1 bar absolute. Line 4772 illustrates resultsobtained when the drum pressure was maintained at 6.9 bars absolute.FIG. 220 demonstrates that a higher mole percent of hydrogen wasproduced in the gas when the drum was maintained at lower pressures. Itis believed that increasing the drum pressure forced additional hydrogeninto the liquids in the drum. The hydrogen will tend to hydrogenateheavy hydrocarbons.

[1644]FIG. 221 illustrates API gravity of liquids produced from the drumas the temperature was increased in the drum. Plot 4782 depicts resultsfrom the high pressure experiment and plot 4780 depicts results from thelow pressure experiment. As illustrated in FIG. 221, higher qualityliquids were produced at the higher drum pressure. It is believed thathigher quality liquids were produced at the higher drum pressure becausemore hydrogenation occurred in the drum during the high pressureexperiment. Although the hydrogen concentration in the gas was lower inthe high pressure experiment, the drum pressures were significantlygreater. Therefore, the partial pressure of hydrogen in the drum wasgreater in the high pressure experiment.

[1645] Controlling a pressure and a temperature within a relativelypermeable formation will, in most instances, affect properties of theproduced formation fluids. For example, a composition or a quality offormation fluids produced from the formation may be altered by alteringan average pressure and/or an average temperature in the selectedsection of the heated portion. The quality of the produced fluids may bedefined by a property which may include, but is not limited to, APIgravity, percent olefins in the produced formation fluids, ethene toethane ratio, percent of hydrocarbons within produced formation fluidshaving carbon numbers greater than 25, total equivalent production (gasand liquid), and/or total liquids production. For example, controllingthe quality of the produced formation fluids may include controllingaverage pressure and average temperature in the selected section suchthat the average assessed pressure in the selected section may begreater than the pressure (p) as set forth in the form of EQN. 34 for anassessed average temperature (T) in the selected section:$\begin{matrix}{p = \exp^{\lbrack{\frac{A}{T} + B}\rbrack}} & (34)\end{matrix}$

[1646] where p is measured in psia (pounds per square inch absolute), Tis measured in Kelvin, and A and B are parameters dependent on the valueof the selected property.

[1647] EQN. 34 may be rewritten such that the natural log of pressuremay be a linear function of an inverse of temperature. This form of EQN.34 may be written as: ln(p)=A/T+B. In a plot of the absolute pressure asa function of the reciprocal of the absolute temperature, A is the slopeand B is the intercept. The intercept B is defined to be the naturallogarithm of the pressure as the reciprocal of the temperatureapproaches zero. Therefore, the slope and intercept values (A and B) ofthe pressure-temperature relationship may be determined from twopressure-temperature data points for a given value of a selectedproperty. The pressure-temperature data points may include an averagepressure within a formation and an average temperature within theformation at which the particular value of the property was, or may be,produced from the formation. For example, the pressure-temperature datapoints may be obtained from an experiment such as a laboratoryexperiment or a field experiment.

[1648] A relationship between the slope parameter, A, and a value of aproperty of formation fluids may be determined. For example, values of Amay be plotted as a function of values of a formation fluid property. Acubic polynomial may be fitted to these data. For example, a cubicpolynomial relationship such as EQN. 35

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄  (35)

[1649] may be fitted to the data, where a₁, a₂, a₃, and a₄ are empiricalconstants that describe a relationship between the first parameter, A,and a property of a formation fluid. Alternatively, relationships havingother functional forms such as another order polynomial or a logarithmicfunction may be fitted to the data. Values of a₁, a₂, . . . , may beestimated from the results of the data fitting. Similarly, arelationship between the second parameter, B, and a value of a propertyof formation fluids may be determined. For example, values of B may beplotted as a function of values of a property of a formation fluid. Acubic polynomial may also be fitted to the data. For example, a cubicpolynomial relationship such as EQN. 36

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄  (36)

[1650] may be fitted to the data, where b₁, b₂, b₃, and b₄ are empiricalconstants that describe a relationship between the parameter B and thevalue of a property of a formation fluid. As such, b₁, b₂, b₃, and b₄may be estimated from results of fitting the data. TABLES 7 and 8 listestimated empirical constants determined for several properties of thetar (or hydrocarbons) for production from Athabasca tar sands. TABLE 7PROPERTY a₁ a₂ a₃ a₄ API Gravity (°) 1.241538 −63.488 399.8138 −2563.58Ethene/Ethane Ratio 703115.4 595728.3 −113788 −6696.36 Weight Percent of−9.98205639 280.8493405 −2882.17 −13199.4 Hydrocarbons Having a CarbonNumber Greater Than 25 Equivalent Liquid −139.727 11019.07 −2874162438177.26 Production (gal/ton)

[1651] TABLE 8 PROPERTY b₁ b₂ b₃ b₄ API Gravity (°) −.00969 0.913396−28.7662 328.0794 Ethene/Ethane Ratio −1502.05 −759.361 131.31174916.12737 Weight Percent of 0.01393835 −0.395164411 4.092876 25.23222Hydrocarbons Having a Carbon Number Greater Thane 25 Equivalent Liquid0.010799 −2.50854 192.3489 −4804.5858 Production (gal/ton)

[1652] To determine an average pressure and an average temperature toproduce a formation fluid having a selected property, the value of theselected property and the empirical constants as described above may beused to determine values for the first parameter A and the secondparameter B according to EQNS. 37 and 38:

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄  (37)

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄.  (38)

[1653] Experimental data from the experiment described above for FIG.193 were used to determine a pressure-temperature relationship relatingto the quality of the produced fluids. Varying the operating conditionsincluded altering temperatures and pressures. Various samples of tarsands were pyrolyzed at various operating conditions. The quality of theproduced fluids was described by a number of desired properties. Desiredproperties included API gravity, an ethene to ethane ratio, equivalentliquids produced (gas and liquid), and percent of fluids with carbonnumbers greater than about 25. Based on data collected from theseequilibrium experiments, families of curves for several values of eachof the properties were constructed as shown in FIGS. 222-225. From thesefigures, EQNS. 39, 40, and 41 were used to describe the functionalrelationship of a given value of a property:

P=exp[(A/T)+B],  (39)

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄  (40)

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄.  (41)

[1654] The generated curves may be used to determine a preferredtemperature and a preferred pressure that produce fluids with desiredproperties. Data illustrating the pressure-temperature relationship of anumber of the desired properties for tar sands samples was plotted in anumber of the following figures.

[1655] In FIG. 222, a plot of gauge pressure versus temperature isdepicted. Lines representing the fraction of products with carbonnumbers greater than about 25 were plotted. For example, when operatingat a temperature of 375° C. and a pressure of 3.8 bars absolute, about5% of the produced fluid hydrocarbons had a carbon number equal to orgreater than 25. At low pyrolysis temperatures and high pressures, thefraction of produced fluids with carbon numbers greater than about 25decreases. Therefore, operating at a high pressure and a pyrolysistemperature at the lower end of the pyrolysis temperature zone tends todecrease the fraction of fluids with carbon numbers greater than 25produced from tar sands.

[1656]FIG. 223 illustrates oil quality produced from tar sands as afunction of pressure and temperature. Lines indicating different oilqualities, as defined by API gravity, are plotted. For example, thequality of the produced oil was about 35° API when pressure wasmaintained at about 5.5 bars absolute and a temperature was about 375°C. Low pyrolysis temperatures and relatively high pressures may producea high API gravity oil.

[1657]FIG. 224 illustrates an ethene to ethane ratio produced from tarsands as a function of pressure and temperature. For example, at apressure of 14.8 bars absolute and a temperature of 375° C., the ratioof ethene to ethane is approximately 0.01. The volume ratio of ethene toethane may predict an olefin to alkane ratio of hydrocarbons producedduring pyrolysis. To control olefin content, operating at lowerpyrolysis temperatures and a higher pressure may be beneficial. Olefincontent may be reduced by operating at a low pyrolysis temperature and ahigh pressure.

[1658]FIG. 225 depicts the yield of equivalent liquids produced from tarsands as a function of temperature and pressure. Line 6808 representsthe pressure-temperature combination at which 8.38×10⁻⁵ m³ of fluid perkilogram of tar sands (20 gallons/ton) is produced. Thepressure/temperature plot results in line 6810 for the production oftotal fluids per ton of tar sands equal to 1.05×10⁻⁵ m³/kg (25gallons/ton). For example, at a temperature of about 325° C. and apressure of about 4.5 bars absolute, the resulting equivalent liquidsproduced was about 8.38×10⁻⁵ m³/kg. As the temperature of the retortincreased and the pressure decreased, the yield of the equivalentliquids produced increased. Equivalent liquids produced is defined asthe amount of liquids equivalent to the energy value of the produced gasand liquids.

[1659] A three-dimensional (3-D) simulation model (STARS, ComputerModeling Group (CMG), Calgary, Canada) was used to simulate an in situconversion process for a tar sands formation. A heat injection rate wascalculated using a separate numerical code (CFX, AEA Technology,Oxfordshire, UK). The initial heat injection rate was calculated at 500watts per foot (1640 watts per meter). The 3-D simulation was based on adilation-recompaction model for tar sands. A target zone thickness of 50m was used. Input data for the simulation were based on averagereservoir properties of the Grosmont formation in northern Alberta,Canada as follows:

[1660] Depth of target zone=280 m;

[1661] Thickness=50 m;

[1662] Porosity=0.27;

[1663] Oil saturation=0.84;

[1664] Water saturation=0.16;

[1665] Permeability=1000 millidarcy;

[1666] Vertical permeability versus horizontal permeability=0.1;

[1667] Overburden=shale; and

[1668] Base rock=wet carbonate.

[1669] Six component fluids were used in the STARS simulation based onfluids found in Athabasca tar sands. The six component fluids were:heavy fluid, light fluid, gas, water, pre-char, and char. The spacingbetween heater wells was set at 9.1 m on a triangular pattern. In onesimulation, eleven horizontal heaters, each with a 91.4 m heater lengthwere used with initial heat outputs set at the previously calculatedvalue of 1640 watts per meter. A vertical production well was placed ata center of the formation.

[1670]FIG. 226 illustrates a plot of percentage oil recovery (percentageof initial volume of oil in place recovered) versus temperature (indegrees Celsius) for a laboratory experiment (data from the pyrolysisexperiments of FIG. 193) and a simulation. The pressure in thelaboratory experiment and in a production well in the simulation wasatmospheric pressure (about 1 bar absolute bottomhole pressure). As canbe seen from the plots, simulation recovery data 9002 was in relativelygood agreement with the experimental recovery data 9000. FIG. 227depicts temperature (in degrees Celsius) versus time (in days) for thelaboratory experiment and the simulation. As is the case with oilrecovery, simulation data 9006 was in relatively good agreement withexperimental data 9004.

[1671]FIG. 228 illustrates a plot of cumulative oil production (in cubicmeters) versus time (in days) for various bottomhole pressures at aproducer well. Plot 4742 illustrates oil production for a pressure of1.03 bars absolute. Plot 4740 illustrates oil production for a pressureof 6.9 bars absolute. FIG. 228 demonstrates that an increase inbottomhole pressure decreases oil production in a tar sands formation.Simulation data illustrated in FIGS. 229, 230, and 231-236 weredetermined for a bottomhole pressure of about 1 bar absolute.

[1672]FIG. 229 illustrates a plot of a ratio of energy content ofproduced fluids from a reservoir against energy input to heat thereservoir versus time (in days). Plot 4752 illustrates the ratio versustime for heating an entire reservoir to a pyrolysis temperature. Plot4750 illustrates the ratio versus time for allowing partial drainage inthe reservoir into a selected pyrolyzation section. FIG. 229demonstrates that allowing partial drainage in the reservoir tends toincrease the energy content of produced fluids versus heating the entirereservoir, for a given energy input into the reservoir.

[1673]FIG. 230 illustrates a plot of weight percentage versus carbonnumber distribution obtained from laboratory experiments and used in thesimulation. Plot 4760 illustrates the carbon number distribution for theinitial tar sand. The initial tar sand has an API gravity of 6°. Plot4762 illustrates the carbon number distribution for in situ conversionof the tar sand up to a temperature of 350° C. Plot 4762 has an APIgravity of 30°. From FIG. 230, it can be seen that the in situconversion process increases the quality of oil found in the tar sands,as evidenced by the increased API gravity and the carbon numberdistribution shift to lower carbon numbers. The lower carbon numberdistribution was evidence that a large portion of the produced fluid wasproduced as a vapor.

[1674]FIG. 231 illustrates percentage cumulative oil recovery versustime (in days) for the simulation using horizontal heaters. As seen fromplot 9014, a total mass recovery approached about 70% at about 1800days. This is comparable to results obtained from the pyrolysisexperiments of FIG. 193 (as shown in FIG. 226). FIG. 232 illustrates oilproduction rates (m³/day) versus time (in days) for heavy hydrocarbons9016 and light hydrocarbons 9018. Heavy hydrocarbon production 9016reached a maximum of about 3 m³/day at about 150 days. Light hydrocarbonproduction 9018 reached a maximum of about 9.6 m³/day at about 950 days.In addition, almost all heavy hydrocarbon production 9016 was completebefore the onset of light hydrocarbon production 9018. The early heavyhydrocarbon production was attributed to production of cold (relativelyunheated and unpyrolyzed) heavy hydrocarbons.

[1675] It should be noted that oil production rates (m³/day), cumulativeoil production data (m³), and other non-averaged number valuesdetermined using the simulations as described herein are calculated forsymmetry elements within the simulation. Thus, absolute values of oilproduction rates, cumulative oil production data, and other non-averagednumber values between simulations with different symmetry elements willdiffer based on the size or scope of the symmetry elements.

[1676] In some embodiments, early production of heavy hydrocarbons maybe undesirable. FIG. 233 illustrates oil production rates (m³/day)versus time (days) for heavy hydrocarbons 9020 and light hydrocarbons9022 with production inhibited for the first 500 days of heating. Heavyhydrocarbon production 9020 in FIG. 233 was significantly lower thanheavy hydrocarbon production 9016 in FIG. 232. Light hydrocarbonproduction 9022 in FIG. 233 was higher than light hydrocarbon production9018 in FIG. 232, reaching a maximum of about 11.5 m³/day at about 950days. The percentage of light hydrocarbons to heavy hydrocarbons wasincreased by inhibiting production the first 500 days of heating.

[1677] Inhibiting production during heating can significantly increasethe pressure in the formation. FIG. 234 depicts average pressure in theformation (bars absolute) versus time (days). Plot 9024 depicts theaverage pressure for inhibited production during the first 500 days ofheating. The average pressure reached a maximum of about 320 barsabsolute at 500 days. Plot 9026 depicts the average pressure forinhibited production until 500 days with four additional verticalproducer wells placed proximate the heater wells. Production through thefour additional vertical producer wells was limited such that smallamounts of hydrocarbons were produced to relieve pressure in theformation. In this case, the average pressure decreased to about 185bars absolute at 500 days. Thus, producing small amounts of hydrocarbonsduring early stages of production can be effective for controllingpressure within the formation.

[1678]FIG. 235 illustrates cumulative oil production (m³) versus time(days) for vertical producer 9030 and horizontal producer 9028 for thesimulation using horizontal heater wells. As shown in FIG. 235, therewas relatively little difference in cumulative oil production betweenusing a horizontal producer in the middle of the formation or a verticalproducer in the simulation. Vertical or slanted wells may be easierand/or cheaper to install than horizontal wells. Using vertical orslanted production wells may improve an economic outlook for a proposedin situ system.

[1679]FIG. 236 illustrates percentage cumulative oil recovery versustime (days) for three different horizontal producer well locations: top9032, middle 9036, and bottom 9034. The highest cumulative oil recoverywas obtained using bottom producer 9034. There was relatively littledifference in cumulative oil recovery between middle producer 9036 andtop producer 9032. FIG. 237 illustrates production rates (m³/day) versustime (days) for heavy hydrocarbons and light hydrocarbons for the middleand bottom producer locations. As seen in FIG. 237, heavy hydrocarbonproduction with bottom producer 9038 was more than heavy hydrocarbonproduction with middle producer 9040. There was relatively littledifference between light hydrocarbon production with bottom producer9042 and light hydrocarbon production with middle producer 9044. Highercumulative oil recovery obtained with the bottom producer (shown in FIG.236) may be due to increased heavy hydrocarbon production.

[1680] A second tar sands simulation for the Grosmont reservoir used sixvertical heater wells and a vertical producer well in a seven spotpattern with a spacing of 9.1 m between wells. The bottomhole pressurein the vertical producer well was about 1 bar absolute. FIG. 238illustrates percentage cumulative oil recovery versus time (in days) forthe second Grosmont tar sands simulation. Plot 9008 shows a total massrecovery approached about 70% after 1800 days, which is comparable toresults of the pyrolysis experiments of FIG. 193 (as shown in FIG. 226).

[1681]FIG. 239 illustrates oil production rates (m³/day) versus time (indays) for heavy hydrocarbons 9010 and light hydrocarbons 9012 for thesecond Grosmont tar sands simulation. FIG. 239 shows that heavyhydrocarbon production 9010 reached a maximum of about 0.08 m³/day atabout 700 days. Light hydrocarbon production 9012 reached a maximum ofabout 0.22 m³/day at about 800 days. The heavy hydrocarbon production(shown in FIG. 239) takes place at a later time than heavy hydrocarbonproduction for horizontal heater wells (shown in FIG. 232).

[1682] Simulations were performed using the 3-D simulation model (STARS)to simulate an in situ conversion process for a tar sands formation. Aseparate numerical code using finite difference simulation (CFX) wasused to calculate heat input data for the formations and well patterns.The heat input data was used as boundary conditions in the 3-Dsimulation model.

[1683]FIG. 240 illustrates a pattern of heater/producer wells used toheat a tar sands formation in the simulation. In the simulation, sixheater/producer wells 6720 were placed in formation 6722. FIG. 241illustrates a pattern of heater/producer wells used in the simulationwith three heater/producer wells 6720, one cold producer well 6724, andthree heater wells 6726. Cold producer well 6724 has no heating elementplaced within the well. FIG. 242 illustrates a pattern of six heaterwells 6726 and one cold producer well 6724 used in the simulation. Thepattern of wells used in each simulation is similar to that for theembodiment described in reference to FIG. 138. Heater wells had ahorizontal length (i.e., length perpendicular to the pattern in thedrawings) of 91.4 m in the simulations.

[1684] Parameters for the simulations are based on formation propertiesof the Peace River basin in Alberta, Canada:

[1685] Formation thickness=28 m, in which the formation has three layers(estuarine, lower estuarine, and fluvial);

[1686] Estuarine thickness 10 m (upper portion of formation);

[1687] porosity 0.28;

[1688] permeability=150 millidarcy;

[1689] vertical permeability/horizontal permeability=0.07;

[1690] oil saturation=0.79;

[1691] Lower estuarine thickness=9 m (middle portion of formation);

[1692] porosity=0.28;

[1693] permeability=825 millidarcy;

[1694] vertical permeability/horizontal permeability=0.6;

[1695] oil saturation=0.81;

[1696] Fluvial thickness=9 m (lower portion of formation);

[1697] porosity=0.30;

[1698] permeability=1500 millidarcy;

[1699] vertical permeability/horizontal permeability=0.7;

[1700] oil saturation=0.81.

[1701] Simulation data illustrated in FIGS. 243-252 were determined fora bottomhole pressure of about 1 bar absolute. FIG. 243 illustratescumulative oil production (m³) versus time (days) for the simulation ofFIG. 240. Plot 6730 illustrates cumulative heavy hydrocarbon productionversus time. Plot 6732 illustrates cumulative light hydrocarbonproduction versus time. As shown in FIG. 243, light hydrocarbonproduction exceeds heavy hydrocarbon production for the case of sixheater/producer wells. Light hydrocarbon production at about 2000 dayswas about 3650 m³, while heavy hydrocarbon production at the same timewas about 2700 m³.

[1702]FIG. 244 illustrates cumulative oil production (m³) versus time(days) for the simulation of FIG. 241. Plot 6734 illustrates cumulativeheavy hydrocarbon production versus time. Plot 6736 illustratescumulative light hydrocarbon production versus time. As shown in FIG.244, light hydrocarbon production exceeds heavy hydrocarbon for thesimulation. Light hydrocarbon production at about 2000 days was about4930 m³, while heavy hydrocarbon production at the same time was about650 m³. In this case, light hydrocarbon production was greater thanheavy hydrocarbon production. A ratio of light hydrocarbon production toheavy hydrocarbon production for this simulation was greater than aratio of light hydrocarbon production to heavy hydrocarbon productionfor the simulation in FIG. 240 (as shown in FIG. 243).

[1703]FIG. 245 illustrates cumulative oil production (m³) versus time(days) for the simulation of FIG. 242. Plot 6738 illustrates cumulativeheavy hydrocarbon production versus time. Plot 6740 illustratescumulative light hydrocarbon production versus time. As shown in FIG.245, heavy hydrocarbon production exceeds that of light hydrocarbonproduction using a cold producer well at the bottom of the formation.Light hydrocarbon production was about 3000 m³ at about 2000 days, whileheavy hydrocarbon production at the same time was about 4100 m³. Lighthydrocarbon production was lower than the previous simulations, whileheavy hydrocarbon production (and total oil production) increased.

[1704]FIG. 246 illustrates cumulative gas production (m³) and cumulativewater production (m³) versus time (days) for the simulation of FIG. 240.Plot 6742 illustrates cumulative water production versus time. Plot 6744illustrates cumulative gas production versus time. FIG. 247 illustratescumulative gas production (m³) and cumulative water production (m³)versus time (days) for the simulation of FIG. 241. Plot 6746 illustratescumulative water production versus time. Plot 6748 illustratescumulative gas production versus time. FIG. 248 illustrates cumulativegas production (m³) and cumulative water production (m³) versus time(days) for the simulation of FIG. 242. Plot 6750 illustrates cumulativewater production versus time. Plot 6752 illustrates cumulative gasproduction versus time. As shown in FIGS. 246, 247, and 248, waterproduction was relatively constant in the three simulations (about 2700m³ barrels after about 2000 days). Gas production was the highest inFIG. 247, with about 4.8×10⁵ m³ after about 2000 days. Gas productionwas the lowest in FIG. 248, at about 3.7×10⁵ m³ at about 3000 days.

[1705]FIG. 249 illustrates an energy ratio versus time for thesimulation of FIG. 240. Plot 6754 illustrates the energy ratio (energyproduced divided by energy injected) versus time (days). FIG. 250illustrates an energy ratio versus time for the simulation of FIG. 241.Plot 6756 illustrates the energy ratio versus time (days). FIG. 251illustrates an energy ratio versus time for the simulation of FIG. 242.Plot 6758 illustrates the energy ratio versus time (days). As shown inFIGS. 249 and 250, the energy ratio in these simulations are relativelysimilar. FIG. 251 shows a greater energy ratio due to the high energycontent of the heavy hydrocarbons produced in the bottom cold producer.However, the heavy hydrocarbons produced in the bottom cold producerwere of lower quality than oil produced with six heater/producer wellsand/or production through an upper portion of the formation.

[1706]FIG. 252 illustrates an average API gravity of produced fluidversus time (days) for the simulations in FIGS. 240-242. Plot 6760illustrates the average API gravity versus time for the simulation ofFIG. 240 using six heater/producer wells. Plot 6762 illustrates theaverage API gravity versus time for the simulation of FIG. 241 usingthree heater/producer wells and a cold production well. Plot 6764illustrates the average API gravity versus time for the simulation ofFIG. 242 using six heater wells and a bottom cold producer. As shown inFIG. 252, higher quality oil (higher average API gravity) was producedfor the simulation of FIG. 241. This may be attributed to moresignificant upgrading of the oil proximate the heater/producer wells andcold producer in the upper portion of the formation. Oil produced in thesimulation of FIG. 241 appears to have a larger vapor phase componentthan oil produced in the simulations of FIGS. 240 and 242.

[1707]FIG. 253 depicts an alternate heater well pattern used in the 3-DSTARS simulation. Heater wells 6726 were placed in a pattern similar tothe heater wells of FIGS. 240-242. A horizontal spacing between heaterwells was about 15 m, as shown in FIG. 253, and the heater wells had ahorizontal length of 91.4 nm. A location of the production well wasvaried between middle producer location 6725 and bottom producerlocation 6727 for the data shown in FIGS. 254, 255, and 256-259.

[1708]FIG. 254 illustrates an energy out/energy in ratio versus time(days) for production through a middle producer location with abottomhole pressure of about 1 bar absolute. The reservoir was treatedby heating the full reservoir uniformly (plot 9048) and by stagedheating of the reservoir (plot 9046). Staged heating of the reservoirincluded turning off the top heaters at 690 days, the middle upperheater at 810 days, and the middle lower heater and bottom heaters at1320 days. As shown in FIG. 254, staged heating 9046 of the reservoirproduced a higher energy out/energy in ratio than full reservoir heating9048. The amount of energy input into the formation is lower with thestaged heating process, which may contribute to the higher energyout/energy in ratio.

[1709]FIG. 255 illustrates percentage cumulative oil recovery versustime (days) for production using a middle producer location and a bottomproducer location with a bottomhole pressure of about 1 bar absolute.Plot 9052 illustrates production using middle producer location. Plot9050 illustrates production using bottom producer location. As shown inFIG. 255, producing through the production well located at the bottom ofthe formation resulted in higher total oil recovery from the formation.However, most of the increased total oil recovery was due to productionof heavy hydrocarbons rather than light hydrocarbons from the formation.Economic considerations may determine a desired ratio of heavyhydrocarbons to light hydrocarbons and locations of production wells toproduce the desired ratio.

[1710]FIG. 260 illustrates cumulative oil produced (cm³/kg) versustemperature (degrees Celsius) for lab pyrolysis experiments 9060 (asdetermined with the experimental apparatus of FIG. 193) and forsimulation 9062 with a bottomhole pressure of about 7.9 bars absolute.As shown in FIG. 260, cumulative oil production versus temperature forthe simulation was in good agreement with pyrolysis experimental data.

[1711]FIG. 256 illustrates cumulative oil production (m³) versus time(days) using a middle producer location and a bottomhole pressure ofabout 7.9 bars absolute. Cumulative heavy hydrocarbon production 9104was about 600 m³ after about 800 days. Cumulative light hydrocarbonproduction 9106 was about 3975 m³ after about 1500 days. Totalcumulative production 9108 was about 4575 m³ after complete lighthydrocarbon production.

[1712]FIG. 257 illustrates API gravity of oil produced and oilproduction rates (m³/day) for heavy hydrocarbons and light hydrocarbonsfor a middle producer location and a bottomhole pressure of about 7.9bars absolute. As shown in FIG. 257, light hydrocarbon production 9112takes place at a later time than heavy hydrocarbon production 9110. APIgravity 9114 of the combined production increased to a maximum of about40° at the same time the light hydrocarbon production rate 9112maximized (about 900 days) and when heavy hydrocarbon production 9110was substantially complete.

[1713]FIG. 258 illustrates cumulative oil production (m³) versus time(days) for a bottom producer location and a bottomhole pressure of about7.9 bars absolute. Cumulative heavy hydrocarbon production 9118 wasabout 3370 m³ after about 1000 days. Cumulative light hydrocarbonproduction 9116 was about 2080 m³ after about 1100 days. Totalcumulative production 9120 was about 5450 m³ after complete lighthydrocarbon production. The earlier production time for the bottomproducer location compared to production with the middle producerlocation (as shown in FIGS. 256 and 257) may be due to an increasedproduction of cold (unpyrolyzed) hydrocarbons at the bottom producerlocation caused by gravity drainage of the fluids. The increasedproduction of heavy (cold) hydrocarbons increased the total cumulativeoil production (total mass recovery) from the formation.

[1714]FIG. 259 illustrates API gravity of oil produced and oilproduction rates (m³/day) for heavy hydrocarbons and light hydrocarbonsfor a bottom producer location and a bottomhole pressure of about 7.9bars absolute. As shown in FIG. 259, light hydrocarbon production 9124takes place at a later time than heavy hydrocarbon production 9122, asshown in FIG. 257 for a middle producer location. API gravity 9126 ofthe combined production increased to a maximum of about 35° at about1200 days, which is about the same time heavy hydrocarbon production wascomplete. The lower API gravity shown in FIG. 259 compared to the APIgravity obtained using the middle producer location (shown in FIG. 257)was probably due to increased production of heavy (cold) hydrocarbonsduring the early stages of production.

[1715]FIG. 261 illustrates oil production rates (m³/day) versus time(days) for heavy hydrocarbons 9128 and light hydrocarbons 9130 producedthrough a middle producer location and a bottomhole pressure of about7.9 bars absolute. The heater well pattern for the simulation wasidentical to the heater well pattern in FIG. 253 with the horizontalheater spacing increased from 15 m to 18.3 m. As shown in FIG. 261,production rates of light hydrocarbons and heavy hydrocarbons for thewider spacing (18.3 m) was relatively similar to production rates forthe narrower spacing (15 m), as shown in FIG. 257. Production startedlater in FIG. 261, however, which may be attributed to a slower heatingrate caused by the wider spacing.

[1716]FIG. 262 illustrates cumulative oil production (m³) versus time(days) for the wider horizontal heater spacing of 18.3 m with productionthrough a middle producer location and a bottomhole pressure of about7.9 bars absolute. Cumulative heavy hydrocarbon production 9132 wasabout 265 m³ after about 800 days. Cumulative light hydrocarbonproduction 9134 was about 5432 m³ after about 2000 days. A totalcumulative production 9136 was about 5700 m³ after completed lighthydrocarbon production. Although the wider heater spacing increased theproduction time (as shown in FIG. 261), the total recovery of oil wasgreater for the wider heater spacing than for the narrower heaterspacing. In addition, the wider heater spacing appeared to increase thepercentage of light hydrocarbons in the total oil recovered (i.e., thelight hydrocarbon versus heavy hydrocarbon ratio) compared to thenarrower spacing (as shown in FIG. 256).

[1717]FIG. 263 depicts another heater well pattern used in the 3-D STARSsimulation. Heater wells 6726 were placed in a triangular pattern.Heater wells had a horizontal length of 91.4 m in the triangularpattern. Production well 6724 was located near the middle of theformation. FIG. 264 illustrates oil production rates (m³/day) versustime (days) for heavy hydrocarbons 9138 and light hydrocarbons 9140produced through production well 6724 located in the middle of theformation in FIG. 263 and a bottomhole pressure of about 7.9 barsabsolute. As shown in FIG. 264, production rates of light hydrocarbonsand heavy hydrocarbons for the triangular pattern were relativelysimilar to production rates for the hexagonal pattern of FIG. 253 (asshown in FIG. 257). The light hydrocarbon production rate in FIG. 264for the triangular pattern was somewhat lower than the light hydrocarbonproduction rate in FIG. 257 for the hexagonal pattern. The lowerproduction rate for the triangular pattern was probably caused by theincreased spacing between heaters in the triangular pattern. Theincreased spacing appeared to cause a larger reduction in the heavyhydrocarbon production rate than in the light hydrocarbon productionrate.

[1718]FIG. 265 illustrates cumulative oil production (m³) versus time(days) for the triangular heater pattern shown in FIG. 263 and abottomhole pressure of about 7.9 bars absolute. Cumulative heavyhydrocarbon production 9142 was about 90 m³ after about 500 days.Cumulative light hydrocarbon production 9144 was about 3020 m³ afterabout 1500 days. A total cumulative production 9146 was about 3100 m³after complete light hydrocarbon production. The triangular heaterspacing appeared to decrease the production rate (as shown in FIG. 264)and the total cumulative production (as shown in FIG. 265). Thetriangular heater spacing increased the percentage of light hydrocarbonsin the total oil recovered (i.e., the light hydrocarbon versus heavyhydrocarbon ratio) relative to the wider heater spacing (as shown inFIG. 262) and the narrower heater spacing (as shown in FIG. 256).

[1719]FIG. 266 illustrates an alternate heater well and producer wellpattern used for a 3-D STARS simulation. Heater wells 6772(a-l) wereplaced horizontally in formation 6770 in an alternating triangularpattern as shown in FIG. 266. Heater wells had a horizontal length of91.4 m in the alternating triangular pattern. A horizontal producer wellwas placed proximate a top of the formation (top production well 6774),in a middle of the formation (middle production well 6776), or proximatea bottom of the formation (bottom production well 6778).

[1720]FIG. 267 illustrates oil production rates (m³/day) versus time(days) for heavy hydrocarbons 9064 and light hydrocarbons 9066 forproduction using bottom production well and a bottomhole pressure ofabout 7.9 bars absolute. As shown in FIG. 267, heavy hydrocarbonproduction 9064 was significant during early stages of production(before about 250 days). After about 200 days, oil production appearedto shift to light hydrocarbon production 9066. Plot 9065 illustratesaverage pressure in the formation versus time. The average pressure inthe formation appeared to rise during the early stages of heavyhydrocarbon production. As light hydrocarbon production began, theaverage pressure began to decrease.

[1721]FIG. 268 illustrates cumulative oil production (m³) versus time(days) for production through a bottom production well and a bottomholepressure of about 7.9 bars absolute. Plot 9068 depicts cumulative heavyhydrocarbon production. Plot 9070 depicts cumulative light hydrocarbonproduction. Plot 9072 depicts total (heavy and light) cumulative oilproduction. As shown in FIG. 268, heavy hydrocarbon production 9068 wasabout 1600 m³ after about 240 days. Light hydrocarbon production wasabout 2900 m³ after about 450 days. Total cumulative oil production wasabout 4500 m³. As shown in FIGS. 267 and 268, heavy hydrocarbonproduction was significant, which is likely caused by gravity drainageof fluids towards the bottom production well. After temperatures in theformation reached pyrolysis temperatures, the cracking of heavyhydrocarbons to form light hydrocarbons in the formation increased andproduction shifted to light hydrocarbon production.

[1722]FIG. 269 illustrates oil production rates (m³/day) versus time(days) for heavy hydrocarbons 9074 and light hydrocarbons 9076 forproduction using a middle production well and a bottomhole pressure ofabout 7.9 bars absolute. As shown in FIG. 269, some heavy hydrocarbonproduction occurred before light hydrocarbon production began. There is,however, less heavy hydrocarbon production than for the simulation usinga bottom production well (shown in FIG. 267). A maximum production rateof heavy hydrocarbons in FIG. 269 was about 9 m³/day while a maximumproduction rate of heavy hydrocarbons in FIG. 267 was about 23 m³/day.Plot 9075 illustrates average pressure in the formation versus time. Theaverage pressure in the formation appeared to rise slightly during theearly stages of heavy hydrocarbon production and decrease slightly withthe onset of light hydrocarbon production.

[1723]FIG. 270 illustrates cumulative oil production (m³) versus time(days) for production through a middle production well and a bottomholepressure of about 7.9 bars absolute. Plot 9078 depicts cumulative heavyhydrocarbon production. Plot 9080 depicts cumulative light hydrocarbonproduction. Plot 9082 depicts total (heavy and light) cumulative oilproduction. As shown in FIG. 270, heavy hydrocarbon production 9078 wasabout 790 m³ after about 225 days. Light hydrocarbon production wasabout 3200 m³ after about 520 days. Total cumulative oil production wasabout 4190 m³. There was slightly less total cumulative oil productionfor a middle production well than for a bottom production well. Thedecreased cumulative oil production in the middle production well islikely caused by increased heavy hydrocarbon production through thebottom production well. As shown in FIGS. 267-270, light hydrocarbonproduction was higher and heavy hydrocarbon production was lower for themiddle production well than for the bottom production well.

[1724]FIG. 271 illustrates oil production rates (m³/day) versus time(days) for heavy hydrocarbon production 9086 and light hydrocarbonproduction 9084 for production using a top production well and abottomhole pressure of about 7.9 bars absolute. As shown in FIG. 271,light hydrocarbon production for the top production well was somewhathigher than light hydrocarbon production from the middle production well(as shown in FIG. 269). Heavy hydrocarbon production for the topproduction well was less than heavy hydrocarbon production for thebottom production well (as shown in FIG. 267). The production of heavyhydrocarbons decreased as the production well was placed closer to thetop of the formation. The decreased production of heavy hydrocarbons maybe caused by gravity drainage of the heavy hydrocarbons as the heavyhydrocarbons are mobilized as well as an increase in production offluids in the vapor phase at the top of the formation. Plot 9085illustrates average pressure in the formation versus time. The averagepressure in the formation appeared to rise significantly until the onsetof light hydrocarbon production.

[1725]FIG. 272 illustrates cumulative oil production (m³) versus time(days) for production through a top production well and a bottomholepressure of about 7.9 bars absolute. Plot 9088 depicts cumulative heavyhydrocarbon production. Plot 9090 depicts cumulative light hydrocarbonproduction. Plot 9092 depicts total (heavy and light) cumulative oilproduction. As shown in FIG. 272, heavy hydrocarbon production 9088 wasabout 790 m³ after about 225 days. Light hydrocarbon production wasabout 3200 m³ after about 520 days. Total cumulative oil production wasabout 4190 m³. Cumulative oil production through the top production wellwas substantially similar to cumulative oil production through themiddle production well. As shown in FIGS. 269-272, heavy hydrocarbonproduction occurred earlier for production through the middle productionwell than for production through the top production well. In FIG. 270,for example, cumulative heavy hydrocarbon production 9078 was about 590m³ at 200 days. In FIG. 272, cumulative heavy hydrocarbon production9088 was about 320 m³ at 200 days. As shown in FIG. 271 for productionthrough the top production well, heavy hydrocarbon production 9086increased when light hydrocarbon production 9084 began. The increasedheavy hydrocarbon production may be caused by vapor phase transport ofheavy hydrocarbons towards the top production well.

[1726]FIG. 273 illustrates oil production rates (m³/day) versus time forheavy hydrocarbons 9094 and light hydrocarbons 9096 for producing fluidsthrough heater wells 6772 a, 6772 b, 6772 c, 6772 d, 6772 e, 6772 f,6772 g, 6772 h, 6772 i, and 6772 j, as shown in FIG. 266 and abottomhole pressure of about 7.9 bars absolute. As shown in FIG. 273,overall heavy hydrocarbon production and most heavy hydrocarbonproduction were significantly reduced prior to light hydrocarbonproduction. Heating of the production wells within the formation mostlikely increased light hydrocarbon production. Cracking of hydrocarbonsat a heated production well tends to increase vapor phase production atthe heated production well.

[1727]FIG. 274 depicts another well pattern used in a simulation. Thewell pattern in FIG. 274 includes the heater pattern of FIG. 266 withthree production wells 9098 placed in an upper portion of the formation.Heater wells had a horizontal length of 91.4 m in the simulation. FIG.275 illustrates oil production rates (m³/day) versus time (days) forheavy hydrocarbons 9100 and light hydrocarbons 9102 for production wells9098 in FIG. 274 and a bottomhole pressure of about 7.9 bars absolute.As shown in FIG. 275, light hydrocarbon and heavy hydrocarbon productionprior to 200 days was slightly higher than light hydrocarbon and heavyhydrocarbon production with top production well (as shown in FIG. 271).The early production of light and heavy hydrocarbons with productionwells 9098 may have been due to the placement of more production wellsin the formation. Placement of more production wells in the formationtends to inhibit the buildup of pressure in the formation by producingat least some hydrocarbons at an earlier time. Therefore, pressurebuildup was inhibited by producing at least some hydrocarbons at lowertemperatures (i.e., temperatures below pyrolysis temperatures).

[1728]FIGS. 276 and 277 illustrate coke deposition near heater wells.FIGS. 276 and 277 show a solid phase concentration (in m³ of soliddivided by m³ of liquid) at a heater well versus time (days). Plot 6804in FIG. 276 depicts the solid phase concentration at heater wells 6772 aand 6772 b (FIG. 266) versus time. Plot 6806 in FIG. 277 depicts thesolid phase concentration at heater wells 6772 k and 67721 versus time.As shown in FIGS. 276 and 277, coke deposition was more significant atheater wells in a bottom portion of the formation. This may have beendue to gravity drainage of liquid hydrocarbons towards the bottom of theformation, the residence time of liquid hydrocarbons in the bottom ofthe formation, and/or temperatures proximate heater wells in the bottomportion of the formation.

[1729] A large pattern simulation of an in situ process in a tar sandsformation was performed using a 3-D simulation (STARS). FIG. 278 depictsa pattern of heat sources 9602 and production wells 9604(A-E) placed intar sands formation 9600 and used in the large pattern simulation. Heatsources 9602 and production wells 9604(A-E) were placed horizontallywithin formation 9600 with a length of 1000 m. Formation 9600 had ahorizontal width of 145 m and a vertical height of 28 m. Five productionwells 9604(A-E) were placed within the pattern of heat sources 9602 andwith the spacings as shown in FIG. 278.

[1730] A first stage of heating included turning on heat sources 9602 infirst section 9606. Production during the first stage of heating wasthrough production well 9604A in first section 9606. A minimum pressurefor production in production well 9604A was set at 6.8 bars absolute.Fluids were produced through production well 9604A as the fluids weremobilized and/or pyrolyzed within formation 9600. The first stage ofheating occurred for the first 360 days of the simulation.

[1731] A second stage of heating included turning on heat sources 9602in second section 9608, third section 9610, fourth section 9612 andfifth section 9614. Heat sources 9602 in second section 9608, thirdsection 9610, fourth section 9612 and fifth section 9614 were turned onat 360 days. Minimum pressure for production in production wells9604(B-E) was set at 6.8 bars absolute.

[1732] Heat sources 9602 in first section 9606 were turned off at 1860days. At 1860 days, production through production well 9604A was alsoshut off. Heat sources 9602 in other sections 9608, 9610, 9612, 9614were similarly turned off after 2200 days. The simulation ended at 2580days with production through production wells 9604(B-E) remaining on.Heat sources 9602 were maintained at a relatively constant heat outputof 1150 watts per meter. FIG. 279 depicts net heater output (J) versustime (days) for the simulation. Controlling the turning on and off ofheat sources 9602 produced the linear net heater output increase betweenabout 360 days and about 2200 days.

[1733] Production after the first stage of heating was through any oneof production wells 9604(A-E). Because fluids were produced throughproduction well 9604A at earlier times, fluids in the formation tendedto flow towards production well 9604A as the fluids were mobilizedand/or pyrolyzed in other sections of formation 9600. Fluid flow waslargely due to vapor phase transport of fluids within formation 9600.

[1734]FIG. 280 depicts average temperature 9640 and average pressure9642 in fifth section 9614. As shown in FIG. 280, pressure 9642 began toincrease in fifth section 9614 after 360 days or when heat sources 9602in the fifth section were turned on. A maximum average pressure in fifthsection remained below about 100 bars absolute around 800 days into thesimulation. Pressure then began to decrease as fluids were mobilizedwithin fifth section 9614 (i.e., the average temperature increased aboveabout 100° C.). The average temperature increased at a relativelyconstant rate from about 360 days until the heat sources were turned offat 2200 days. The maximum average temperature in the fifth section wasmaintained below about 400° C.

[1735]FIG. 281 depicts oil production rate (m³/day) versus time (days)as calculated in the simulation. As shown in FIG. 281, oil productionslowly increases for approximately the first 1500 days and thenincreased rapidly after about 1500 days to a maximum of about 880 m³/dayat about 1785 days. After about 1785 days, production rate decreased asa majority of fluids are produced from formation 9600. The highproduction rate at about 1785 days may be due to a high rate of vaporphase transport in the formation following pyrolysis of hydrocarbons inthe formation.

[1736]FIG. 282 depicts cumulative oil production (m³) versus time (days)as calculated in the simulation. As shown in FIG. 282, a majority ofcumulative oil production occurred between about 1000 days and about2200 days.

[1737]FIG. 283 depicts gas production rate (m³/day) versus time (days)as calculated in the simulation. As shown in FIG. 283, gas productionslowly increases for approximately the first 1500 days and thenincreased rapidly after about 1500 days to a maximum of about 235000m³/day at about 1800 days. The maximum gas production rate occurred at asubstantially similar time to the maximum oil production rate shown inFIG. 281. Thus, the maximum oil production rate may be primarily due toa high gas production rate.

[1738]FIG. 284 depicts cumulative gas production (m³) versus time (days)as calculated in the simulation. As shown in FIG. 284, a majority ofcumulative gas production occurred between about 1000 days and about2200 days.

[1739]FIG. 285 depicts energy ratio (energy output in fluids versusenergy input from heat sources) versus time (days) as calculated in thesimulation. As shown in FIG. 285, the energy ratio increased during thefirst stage of heating as fluids are produced. After each successivestage of heating begins, there was an initial decrease in the energyratio. The energy ratio, however, continued to increase overall asfluids were produced from the formation during later stages of heating.

[1740]FIG. 286 depicts average density (kg/m³) of oil in the formationversus time (days). As shown in FIG. 286, the average density of oil inthe formation begins to decrease as the formation is heated. The densitymost likely decreases due to increased generation of vapors as theformation is heated. After about 1800 days, most oil is in the vaporphase and the density remains relatively constant with time.

Further Improvements

[1741] Formation fluid produced from a relatively permeable formationduring treatment may include a mixture of different components. Toincrease the economic value of products generated from the formation,formation fluid may be treated using a variety of treatment processes.Processes utilized to treat formation fluid may include distillation(e.g., atmospheric distillation, fractional distillation, and/or vacuumdistillation), condensation (e.g., fractional), cracking (e.g., thermalcracking, catalytic cracking, fluid catalytic cracking, hydrocracking,residual hydrocracking, and/or steam cracking), reforming (e.g., thermalreforming, catalytic reforming, and/or hydrogen steam reforming),hydrogenation, coking, solvent extraction, solvent dewaxing,polymerization (e.g., catalytic polymerization and/or catalyticisomerization), visbreaking, alkylation, isomerization, deasphalting,hydrodesulfurization, catalytic dewaxing, desalting, extraction (e.g.,of phenols, other aromatic compounds, etc.), and/or stripping.

[1742] Formation fluids may undergo treatment processes in a first insitu treatment area as the formation fluid is generated and produced, ina second in situ treatment area where a specific treatment processoccurs, and/or in surface treatment units. A “surface treatment unit” isa unit used to treat at least a portion of formation fluid at thesurface. Surface treatment units may include, but are not limited to,reactors (e.g., hydrotreating units, cracking units, ammonia generatingunits, fertilizer generating units, and/or oxidizing units), separatingunits (e.g., air separating units, liquid-liquid extraction units,adsorption units, absorbers, ammonia recovery and/or generating units,vapor/liquid separating units, distillation columns, reactivedistillation columns, and/or condensing units), reboiling units, heatexchangers, pumps, pipes, storage units, and/or energy producing units(e.g., fuel cells and/or gas turbines). Multiple surface treatment unitsused in series, in parallel, and/or in a combination of series andparallel are referred to as a surface facility configuration. Surfacefacility configurations may vary dramatically due to a composition offormation fluid as well as the products being generated.

[1743] Surface treatment configurations may be combined with treatmentprocesses in various surface treatment systems to generate a multitudeof products. Products generated at a site may vary with local and/orglobal market conditions, formation characteristics, proximity offormation to a purchaser, and/or available feedstocks. Generatedproducts may be utilized on site, transferred to another site for use,and/or sold to a purchaser.

[1744] Feedstocks for surface treatment units may be generated intreatment areas and/or surface treatment units. A “feedstock” is astream containing at least one component required for a treatmentprocess. Feedstocks may include, but are not limited to, formationfluid, synthetic condensate, a gas stream, a water stream, a gasfraction, a light fraction, a middle fraction, a heavy fraction,bottoms, a naphtha fraction, a jet fuel fraction, a diesel fraction,and/or a fraction containing a specific component (e.g., heart fraction,phenols containing fraction, etc.). In some embodiments, feedstocks arehydrotreated prior to entering a surface treatment unit. For example, ahydrotreating unit used to hydrotreat a synthetic condensate maygenerate hydrogen sulfide to be utilized in the synthesis of afertilizer such as ammonium sulfate. Alternatively, one or morecomponents (e.g., heavy metals) may have been removed from formationfluids prior to entering the surface treatment unit.

[1745] In alternate embodiments, feedstocks for in situ treatmentprocesses may be generated at the surface in surface treatment units.For example, a hydrogen stream may be separated from formation fluid ina surface treatment unit and then provided to an in situ treatment areato enhance generation of upgraded products. In addition, a feedstock maybe injected into a treatment area to be stored for later use.Alternatively, storage of a feedstock may occur in storage units on thesurface.

[1746] The composition of products generated may be altered bycontrolling conditions within a treatment area and/or within one or moresurface treatment units. Conditions within the treatment area and/or oneor more surface treatment units which affect product compositioninclude, but are not limited to, average temperature, fluid pressure,partial pressure of H₂, temperature gradients, composition of formationmaterial, heating rates, and composition of fluids entering thetreatment area and/or the surface treatment unit. Many different surfacefacility configurations exist for the synthesis and/or separation ofspecific components from formation fluid.

[1747] Formation fluid may be produced from a formation through awellhead. As shown in FIG. 287, wellhead 7012 may separate formationfluid 7010 into gas stream 7022, liquid hydrocarbon condensate stream7024, and water stream 7026. Alternatively, formation fluid may beproduced from a formation through a wellhead and flow to a separatingunit, where the formation fluid is separated into a gas stream, a liquidhydrocarbon condensate stream, and a water stream. A portion of the gasstream, the liquid hydrocarbon condensate stream, and/or the waterstream may flow to one or more surface treatment units for use in atreatment process. Alternatively, a portion of the gas stream, theliquid hydrocarbon condensate stream, and/or the water stream may beprovided to one or more treatment areas.

[1748] In some embodiments, formation fluid may flow directly from theformation to a surface treatment unit to be treated. An advantage oftreating formation fluid before separation may be a reduction in thenumber of surface treatment units required. Reducing the number ofsurface treatment units may result in decreased capital and/or operatingexpenses for a treatment system for formations.

[1749] Formation fluid may exit the formation at a temperature in excessof about 300° C. Utilizing thermal energy within the formation fluid mayreduce an amount of energy required by the treatment system. In certainembodiments, formation fluid produced at an elevated temperature may beprovided to one or more surface treatment units. Formation fluid mayenter the surface treatment unit at a temperature greater than about250° C., 275° C., 300° C., 325° C., or 350° C. Alternatively, thermalenergy from formation fluid may be transferred to other fluids utilizedby the surface facility configuration and/or the in situ treatmentprocess.

[1750] As shown in FIG. 288, formation fluid 7010 produced from wellhead7020 may flow to heat exchange unit 7030. Heat exchange fluid 7034 mayflow into heat exchange unit 7030. Thermal energy from formation fluid7010 may be transferred to heat exchange fluid 7034 in heat exchangeunit 7030 to generate heated fluid 7036 and cooled formation fluid 7032.Heat exchange fluid 7034 may include any fluid stream produced from aformation (e.g., formation fluid, pyrolysis fluid, water, and/orsynthesis gas), and/or any fluid stream generated and/or separated outwithin a surface treatment unit (e.g., water stream, light fraction,middle fraction, heavy fraction, hydrotreated liquid hydrocarboncondensate stream, jet fuel stream, etc.).

[1751] In some in situ conversion process embodiments, a heat exchangeunit may be used to increase a temperature of the formation fluid anddecrease a temperature of the heat exchange fluid to generate a cooledfluid and a heated formation fluid. For example, pyrolysis fluids may beproduced from a first treatment area at a temperature of about 300° C.Synthesis gas may be produced from a second treatment area at atemperature of about 600° C. The pyrolysis fluids and synthesis gas mayflow in separate conduits to distant surface treatment units. Heat lossmay cause the pyrolysis fluids to condense before reaching a distantsurface treatment unit for treatment. Various configurations ofconduits, known in the art, may be used to form a heat exchange unit totransfer thermal energy from the synthesis gas to the pyrolysis fluidsto decrease, or prevent, condensation of the pyrolysis fluids.

[1752] In conventional treatment processes, hydrocarbon fluids producedfrom a formation may be separated into at least two streams, including agas stream and a synthetic condensate stream. The gas stream may containone or more components and may be further separated into componentstreams using one or more surface treatment units. The liquidhydrocarbon condensate stream, or synthetic condensate stream, maycontain one or more components that are separated using one or moresurface treatment units. In some embodiments, formation fluid may bepartially cooled to enhance separation of specific components. Forexample, formation fluid may flow to a heat exchange unit to reduce atemperature of the formation fluid. Then, the formation fluid may beprovided to a separating unit such as a distillation column and/or acondensing unit.

[1753] Formation fluid may be hydrotreated prior to separation into agas stream and a liquid hydrocarbon condensate stream. Alternatively,the gas stream and/or the liquid hydrocarbon condensate stream may behydrotreated in separate hydrotreating units prior to further separationinto component streams. “Synthetic condensate” is the liquid componentof formation fluid that condenses.

[1754] In an embodiment, synthetic condensate 7015 flows to surfacefacilities configuration illustrated in FIG. 289. Synthetic condensate7015 may be separated into several fractions in fractionator 7040. Insome embodiments, synthetic condensate stream 7015 is separated intofour fractions. Light fraction 7042, middle fraction 7044, and heavyfraction 7046 may flow to hydrotreating units 7050, 7052, 7054.Hydrotreating units 7050, 7052, 7054 may upgrade hydrocarbons withinfractions 7042, 7044, and 7046 to form light fraction 7053, middlefraction 7055, and/or heavy fraction 7057. In addition, bottoms fraction7048 may be generated. Bottoms fraction 7048 may flow to an in situtreatment area or a surface facility for further processing. In someembodiments, the use of a synthetic condensate stream from which sulfurcontaining compounds have been removed, for example, by hydrotreating ora liquid-liquid extraction process, may increase an effective life ofthe hydrotreating units.

[1755] In an in situ conversion process embodiment, a fractionation unitmay separate a feedstock into a light fraction, a heart cut, a middlecut, and/or a heavy fraction. The composition of the heart cut may becontrolled by removing fluid for the heart cut at a point in thefractionator having a given temperature. After the heart cut has beenseparated, the heart cut may flow to one or more surface treatment unitsincluding, but not limited to, a hydrotreater, a reformer, a crackingunit, and/or a component recovery unit. For example, when a naphthalenefraction is desired, a heart cut may be taken from a point in thefractionator resulting in production of a stream having an atmosphericpressure true boiling point temperature greater than about 210° C. toless than about 230° C. This may correspond to the boiling point rangefor naphthalene. Components that can be separated from a syntheticcondensate in a “heart cut” may include, but are not limited to,mono-aromatic hydrocarbons (e.g., benzene, toluene, ethyl benzene,and/or xylene), naphthalene, anthracene, and/or phenols.

[1756] Temperatures at which components are separated from the formationfluid during distillation or condensation may be affected by theconcentration of water (e.g., steam) in the formation fluid. Steam maybe present in the formation fluid in varying concentrations, due tovarying water contents of formations and variations in steam generationduring treatment. In some embodiments, a steam content of formationfluid may be measured as the formation fluid is produced. The steamcontent may be used to adjust one or more operating conditions inseparating units to enhance separation of fractions.

[1757] Formation fluid may flow to one or more distillation columnspositioned in series to remove one or more fractions in succession. Theone or more fractions from the fluids may be used in one or more surfacetreatment units. “Serial fractional separation” is the removal of two ormore fractions from formation fluid in series. Some of the formationfluid flows to two or more separation units in series, and eachseparation unit may remove one or more components from the formationfluid. For example, formation fluid may be separated into a gas streamand a synthetic condensate. A “naphtha cut” may be separated from thesynthetic condensate. The “naphtha cut” may be further separated into a“phenols cut.” Separating successively smaller cuts from the formationfluid may allow the subsequent treatment units to be smaller and lesscostly, since only a portion of the formation fluid needs to be treatedto produce a specific product. In addition, molecular hydrogen may beseparated for use in one or more of the upstream or downstreamprocesses.

[1758]FIG. 290 depicts a serial fractional system. Synthetic condensate7015 may flow to separating unit 7060, where it is separated into two ormore fractions: light fraction 7062 and heavy fraction 7064. Lightfraction 7062 may flow to heat exchanger 7065 to generate cooled lightfraction 7066, which is separated into light fraction 7072 in separatingunit 7070. Heat exchanger 7075 may remove thermal energy from lightfraction 7072 to cooled light fraction 7076, which then flows toseparating unit 7080. Naphtha fraction 7082 may be separated from cooledlight fraction 7076. Naphtha fraction 7082 may be further separated intoolefin generating compound fraction 7092 in separating unit 7090 afterbeing cooled in heat exchanger 7085 to form cooled naphtha fraction7086. Olefin generating compound fraction 7092 may flow to an olefingenerating unit to be converted to olefins. Fractions 7064, 7074, 7084,7094 may flow to one or more surface treatment units and/or in situtreatment areas for additional treatment. Extracting thermal energy fromfractions 7062, 7072, 7082, and/or 7092 may increase an energyefficiency of the process by utilizing the heat in the fluids. Inalternate embodiments, light fractions (e.g., light fraction 7062, lightfraction 7072, and/or naphtha fraction 7082) may be heated in heatexchanging units 7065, 7075, 7085 prior to entering the one or moreseparation units.

[1759] As shown in FIG. 291, an embodiment of a surface facility portionutilizes some of heavy fractions 7064, 7074, 7084, 7094 as a recyclestream. Some of heavy fractions 7064, 7074, 7084, 7094 removed fromseparation units 7060, 7070, 7080, 7090 may flow to reboilers 7067,7077, 7087, 7097. Recycle streams 7069, 7079, 7089, 7099 may flow fromreboilers 7067, 7077, 7087, 7097 to separation units 7060, 7070, 7080,7090 for further upgrading. In some embodiments, steam may be providedto heavy fractions 7064, 7074, 7084, 7094 to form recycle streams. Insome embodiments, a separating system for treating formation fluid mayinclude a combination of heat exchangers, reboilers, and/or theinjection of steam.

[1760] In certain surface facility embodiments, catalysts may be used inseparating units to upgrade hydrocarbons in formation fluid as thehydrocarbons are being separated into the various fractions. In someembodiments, reactive separating units may contain catalysts thatenhance hydrocarbon upgrading through hydrotreating. Molecular hydrogenpresent in the feedstock may be sufficient to hydrotreat hydrocarbonswithin the feedstock. In alternate embodiments, molecular hydrogen maybe provided to a feedstock entering a reactive separating unit or to thereactive separating unit to enhance hydrogenation.

[1761] Reactive distillation columns may be used to treat a syntheticcondensate such as synthetic condensate and/or hydrotreated syntheticcondensate in some embodiments. A reactive distillation column maycontain a catalyst to increase hydrotreating of hydrocarbons in fluidspassing through the reactive distillation column. In certainembodiments, the catalyst may be a conventional catalyst such as metalon an alumina substrate.

[1762] As illustrated in FIG. 292, multiple distillation columns 7100,7120, 7130, 7140 may be used to separate synthetic condensate 7015 intofractions. Distillation columns 7100, 7120, 7130, 7140 may containcatalyst 7052, which enables hydrocarbons within synthetic condensate7015 to be upgraded within distillation columns 7100, 7120, 7130, 7140through hydrotreating. Molecular hydrogen stream 7105 may be added todistillation columns 7100, 7120, 7130, 7140 to enhance hydrotreating ofhydrocarbons within synthetic condensate stream 7015 in distillationcolumns 7100, 7120, 7130, 7140. Molecular hydrogen stream 7105 may comefrom surface treatment units and/or produced formation fluids. Fractionsremoved from distillation column 7100 may include light fraction 7102,middle fraction 7104, heavy fraction 7106, and bottoms 7108.

[1763] In an embodiment, light fraction 7102 flows to separating unit7110 that separates light fraction 7102 into gaseous stream 7112, lightfraction 7114, and recycle stream 7116. Light fraction 7114 may flow toreactive distillation column 7120 to be separated and upgraded. Indistillation column 7120, light fraction 7114 may be converted intolight fraction 7122. A portion of light fraction 7122 may flow toreboiler 7125 and then flow to distillation column 7120 as recyclestream 7128. Light stream 7126 may flow to a surface treatment unit suchas a reforming unit, an olefin generating unit, a cracking unit, and/ora separating unit. The reforming unit may alter light stream 7126 togenerate aromatics and hydrogen. Alternatively, light stream 7126 may beused to generate various types of fuel (e.g., gasoline). Light stream7126 may, in certain embodiments, be blended with other hydrocarbonfluids to increase a value and/or a mobility of the hydrocarbon fluids.In some embodiments, light stream 7126 may be a naphtha stream.

[1764] In some embodiments, middle fraction 7104 flows into reactivedistillation column 7130. Middle fraction 7104 may be converted intomiddle fraction 7132 and recycle stream 7134 in reactive distillationcolumn 7130. Recycle stream 7134 may flow into distillation column 7100.A portion of middle fraction 7132 may flow into reboiler unit 7135 to bevaporized and enter distillation column 7130 as recycle stream 7138.Middle stream 7136 may be provided to a market and/or flow to a surfacetreatment unit for further treatment.

[1765] Heavy fraction 7106 may flow into distillation column 7140. Heavyfraction 7142 and recycle stream 7144 may be generated in reactivedistillation column 7140. Recycle stream 7144 may flow into distillationcolumn 7100. A portion of heavy fraction 7142 may flow into reboilerunit 7145 to be vaporized and enters distillation column 7140 as recyclestream 7148. Heavy stream 7146 may be provided to a market and/or flowto a surface treatment unit and/or in situ treatment area for furthertreatment.

[1766] Bottoms fraction 7108 may be removed from distillation column7100. A portion of bottoms fraction 7108 may be vaporized in reboilerunit 7150 and enter distillation column 7100 as recycle stream 7152.Bottoms stream 7109 may be cooled in heat exchange units. In certainembodiments, a portion of a bottoms fraction may be used as a feedstockfor an olefin plant and/or an in situ treatment area. In someembodiments, a portion of a bottoms fraction may flow to a hydrocrackingunit to form a transportation fuel stream.

[1767] In some embodiments, formation fluid produced from the ground maybe partially cooled to recover thermal energy from the fluid. Inaddition, formation fluid may be cooled to a temperature at which adesired component is removed from the formation fluid. Heat exchangingunits may remove thermal energy from the formation fluid such that atemperature within the formation fluid is reduced to a temperature atwhich one or more components are separated from formation fluid.Formation fluid may be provided to a distillation column where theformation fluid is further separated into a liquid stream and a vaporstream. The vapor stream may be provided to a heat exchanging unit toremove thermal energy from the vapor stream. The vapor stream may befurther separated in a distillation column. In some embodiments,multiple distillation columns may be arranged to separate the vaporstream into one or more fractions.

[1768] In some embodiments, formation fluid 7010 flows into condensingunit 7160 as shown in FIG. 293. Condensing unit 7160 may separateformation fluid 7010 into gas fraction 7162, light fraction 7164, heavyfraction 7166, and/or heart cut 7168. Gas fraction 7162, light fraction7164, heavy fraction 7166, and/or heart cut 7168 may flow to a surfacetreatment unit for additional treatment.

[1769] An example of a surface facility configuration for treatingformation fluid is illustrated in FIG. 294. Formation fluid 7010 may beproduced through wellhead 7020 and cooled in one or more heat exchangeunits 7170. Cooled formation fluid 7172 may be condensed in condensingunit 7175 to form condensed formation fluid 7176. Condensed formationfluid 7176 may be separated in processing unit 7180 into gas stream 7182and synthetic condensate 7015. Gas stream 7182 may be compressed andseparated in compressor 7185 into gas stream 7186 and hydrocarboncontaining fluids 7187. Hydrocarbon containing fluids 7187 may be heatedin heater 7188. Heated hydrocarbon containing fluids 7189 may beseparated into gas stream 7192 and naphtha stream 7126 in processingunit 7190. Gas stream 7186 and gas stream 7192 may flow into expander7195. Expander 7195 allows fluids within gas stream 7186 and gas stream7192 to expand into light off-gas 7196.

[1770] In an embodiment, synthetic condensate stream 7015 is pumped tohydrotreating unit 7200 to be hydrotreated. Hydrotreated syntheticcondensate stream 7202 may flow through heat exchanging units 7170 to beheated. Heated and hydrotreated synthetic condensate stream 7205 may beseparated into a mixture of non-condensable hydrocarbons 7208 andhydrocarbon containing fluid 7210 in processing unit 7206. Hydrocarboncontaining fluid 7210 may be pumped through heat exchange units 7170 toform heated hydrocarbon containing fluid 7212. Heated hydrocarboncontaining fluid 7212 may be further heated in heating unit 7214 to formheated hydrocarbon containing fluid 7216. Heated hydrocarbon containingfluid 7216 and non-condensable hydrocarbons 7208 may be distilled indistillation column 7220 to form light fraction 7042, middle fraction7044, heavy fraction 7046, and bottoms 7228. Light fraction 7042 may becooled in heat exchange unit 7234. Cooled light fraction 7222 may beseparated into heavy off-gas 7224, water stream 7272, and hydrocarboncondensate stream 7238 in process unit 7236. Hydrocarbon condensatestream 7238 may be split into at least two streams, including recyclestream 7229 and light fraction 7227. Light fraction 7227 may be added tolight stream 7126. Olefins may be generated from light stream 7126 in areforming unit. Alternatively, light stream 7126 may be used to generatevarious types of fuel. Light stream 7126, in certain embodiments, may beblended with other hydrocarbon fluids to increase a value and/or amobility of the hydrocarbon fluids.

[1771] In some embodiments, middle fraction 7044 flows to distillationcolumn 7240. Recycle stream 7244 and middle fraction 7242 may begenerated in distillation column 7240. Recycle stream 7244 may flow todistillation column 7220. Reboiler 7246 may separate middle fraction7242 into recycle stream 7248 and hot middle fraction 7250. Recyclestream 7248 flows to distillation column 7240. Hot middle fraction 7250may be cooled in heat exchange units 7252 to form cooled middle fraction7254. In addition, cooled middle fraction 7254 may flow into acondensing unit to form a middle stream. Alternatively, hot middlefraction 7250 may flow directly from reboiler 7246 to a condensing unitto form a middle stream.

[1772] In an embodiment, distillation column 7270 separates heavyfraction 7046 into recycle stream 7256 and heavy fraction 7258. Recyclestream 7256 may flow to distillation column 7220. Heavy fraction 7258may flow to reboiler 7260. Reboiler 7260 may separate heavy fraction7258 into recycle stream 7262 and heated heavy fraction 7264. Heatedheavy fraction 7264 may be cooled in heat exchange units 7266 to formcooled heavy fraction 7268. In some embodiments, cooled heavy fraction7268 may flow into a condensing unit. Alternatively, heavy fraction 7264may flow from reboiler 7260 to a condensing unit to form a heavy stream.

[1773] In certain embodiments, bottoms fraction 7228 is removed fromdistillation column 7220 and is cooled in heat exchange units 7230 toform cooled bottoms fraction 7232. In some embodiments, cooled bottomsfraction 7232 may flow into a condensing unit to form a condensate.Alternatively, bottoms fraction 7228 may flow directly from distillationcolumn 7220 to a condensing unit.

[1774] In alternate embodiments, distillation columns 7220, 7240, and/or7270 may contain catalysts to upgrade hydrocarbons. The catalysts may behydrotreating and/or cracking catalysts. In some embodiments, anadditional molecular hydrogen stream may be added to distillationcolumns 7220, 7240, and/or 7270 that contain such catalysts.

[1775] Formation fluid may contain substances that compromise surfacetreatment units by altering catalytic surfaces and/or by causingcorrosion. Many surface treatment units may require the removal of thesesubstances prior to treatment in the surface treatment unit. Componentsin formation fluid that may affect a life span and/or efficiency of thesurface treatment unit include heteroatoms (e.g., nitrogen, sulfur, andwater). For example, water decreases the catalytic ability ofconventional hydrotreating catalysts. In some embodiments, use of aconventional hydrotreating unit may require separation of water fromformation fluid prior to treatment. In addition, sulfur containingcompounds may cause corrosion of a surface treatment unit and decreasethe catalytic ability of certain catalysts used in the surface treatmentunit. Removal of sulfur containing compounds from formation fluid mayincrease the value of produced fluid and permit processing of the lowersulfur material in process units not designed for untreated producedfluid.

[1776] Components that foul or corrode surface treatment units may beremoved using a variety of methods including, but not limited to,hydrotreating, solvent extraction, a desalting process, and/orelectrostatic precipitation. In some embodiments, a portion of the waterpresent in formation fluid may be removed from formation fluid as theformation fluid is separated into a gas stream and a liquid hydrocarboncondensate stream.

[1777] In some embodiments, a desalting process may reduce salts information fluid and/or any water or fluid separated in a surfacetreatment unit. The desalting process may include, but is not limitedto, chemical separation, electrostatic separation, and/or filtration ofwater/fluid through a porous structure (e.g., water or fluid may befiltered through diatomaceous earth).

[1778] Heteroatoms may also be removed from formation fluid using anextraction process. Solvents may include, but are not limited to, aceticacid, sulfuric acid, and/or formic acid. Heteroatoms in acidic form,such as phenols and some sulfur compounds, may be removed by extractionwith basic solutions (e.g., caustic or aqueous ammonia). Extraction mayvary with a temperature of formation fluid and/or solvent, a solvent tooil ratio, and/or an acid strength of the acidic solvents. An effectivesolvent may be characterized by features including, but not limited to,inhibition of emulsion formation, immiscibility with feedstock, rapidphase separation, and/or high capacity. Removal of nitrogen containingcomponents by an extraction process may decrease hydrogen uptake and thehydrotreating severity required in subsequent hydrotreating units,thereby reducing operating and capital costs.

[1779] Enactment of more stringent regulatory standards for sulfur inhydrocarbon containing products may require a higher severity to removesulfur from the products. In some circumstances, sulfur may be removedfrom formation fluid prior to separating the fluid into streams tofacilitate removal of a maximum amount of sulfur. Similarly, formationfluid may be hydrotreated prior to separation into streams to decreasean overall cost of processing formation fluid. Subsequent sulfur removaland/or hydrotreating may further improve the quality of hydrocarbonfluids produced from the formation fluid.

[1780] Conventional refiners may not handle high concentrations ofheteroatoms in fluid fractions (e.g., naphtha, jet, and diesel).Hydrotreating may produce a product that would be acceptable to arefiner. Another approach, or a complementary approach, may be tooptimize the combination of the in situ conversion process conditionsand surface hydrotreating processes to obtain the highest product valuemix at the lowest total cost. For example, one in situ conversionprocess change that may improve properties of the liquid formation fluidis the use of backpressure on the formation during the heating process.Maintaining a fluid pressure by adjusting the backpressure may produce amuch lighter and more hydrogen rich product.

[1781] Hydrotreating a fluid may alter many properties of the fluid.Hydrotreating may increase the hydrogen content of the hydrocarbonswithin the fluid and/or the volume of fluid. In addition, hydrotreatingmay reduce a content of heteroatoms such as oxygen, nitrogen, or sulfurin the fluid. For example, nitrogen removed from the fluid duringhydrotreating may be converted into ammonia. Removed sulfur may beconverted into hydrogen sulfide. Feedstocks for hydrotreating units mayinclude, but are not limited to, formation fluid and/or any fluidgenerated or separated in a surface treatment unit (e.g., syntheticcondensate, light fraction, middle fraction, heavy fraction, bottoms,heart cut, pyrolysis gasoline, and/or molecular hydrogen generated at anolefin generating plant).

[1782] Olefins may be present in formation fluid as a result of in situtreatment processes. In some embodiments, olefin generating compoundsmay be produced in formation fluid. “Olefin generating compounds” arehydrocarbons having a carbon number equal to and/or greater than 2 andless than 30 (e.g., carbon numbers from 2 to 7). These olefin generatingcompounds may be converted into olefins, such as ethylene and propylene.Process conditions during treatment within a treatment area of aformation may be controlled to increase, or even to maximize, productionof olefins and/or olefin generating compounds within the formationfluid.

[1783] In an embodiment, olefins and/or olefin generating compoundsproduced in the formation fluid may be separated from the formationfluid using one or more surface facility configurations. Separation ofolefins and/or olefin generating compounds from formation fluid mayoccur in, but is not limited to, a gas treating unit, a distillationunit, and/or a condensing unit. Olefin generating compounds may beseparated from formation fluid to form an olefin feedstock used togenerate olefins.

[1784] Olefin feedstocks may include formation fluid, syntheticcondensate, a naphtha stream, a heart cut (e.g., a stream containinghydrocarbons having carbon number from two to seven), a propane stream,and/or an ethane stream. For example, formation fluid may be separatedinto a liquid stream (e.g., synthetic condensate) and a gas stream. Thegas stream may be further separated into four or more fractions. Thefractions may include, but are not limited to, a methane fraction, amolecular hydrogen fraction, a gas fraction, and an olefin generatingcompound fraction. In some embodiments, olefin feedstocks may have beenhydrotreated and/or have had one or more components (e.g., arsenic,lead, mercury, etc.) removed prior to entering the olefin generatingunit.

[1785] Many different surface facility configurations may produceolefins from an olefin feedstock. The particular configuration utilizedfor synthesis of olefins may depend on a type of formation treated, acomposition of formation fluid, and/or treatment process conditions usedin situ such as a temperature, a pressure, a partial pressure of H₂,and/or a rate of heating.

[1786] Conversion of formation fluid and/or olefin generating compoundsto olefins occurs when hydrocarbons in formation fluid are heatedrapidly to cracking temperatures and then quenched rapidly to inhibitsecondary reactions (e.g., recombination of hydrogen with olefins).Prolonged heating may result in the production of coke and, thus,quenching the reaction is vital to enhancing olefin generation. Atemperature required for olefin generation may be greater than about800° C. Formation fluid may exit the formation at a temperature greaterthan about 200° C. In certain embodiments, formation fluid may beproduced from wells containing a heat source such that a temperature ofat least a portion of the formation fluid is about 700° C. Therefore,additional heating may be required for generation of olefins. Formationfluid may flow to an olefin generating unit where fluid is initiallyheated and then cooled to quench the reaction to enhance production ofolefins.

[1787]FIG. 295 depicts an embodiment of surface facility units used togenerate olefins from an olefin feedstock that contains olefingenerating compounds. The hydrogen content of hydrocarbons withinformation fluid may be increased to greater than about 12 weight % bycontrolling one or more conditions within a treatment area from whichformation fluid 7010 is produced. For example, maintaining a pressuregreater than about 7 bars (100 psig) and a temperature less than about375° C. within a treatment area may generate formation fluid havinghydrocarbons with a hydrogen content greater than about 12 weight %. Ahydrogen content of greater than 12 weight % in the hydrocarbons offormation fluid may decrease the content of heavy hydrocarbons and/orundesirable compounds in the formation fluid produced.

[1788] In an embodiment, formation fluid 7010 (e.g., formation fluidhaving hydrocarbons with a hydrogen content greater than about 12%)flows directly from wellhead 7020 into olefin generating unit 7280 to beconverted to olefin stream 7282. In some embodiments, the olefingenerating unit may be a steam cracker. Formation fluid 7010 may flowinto olefin generating unit 7280 at a temperature greater than about300° C. in certain embodiments. Thermal energy within the formationfluid may be utilized in the generation of olefins from the olefingenerating compounds. In an embodiment, formation fluid may containsteam. Steam in formation fluid may be utilized in the generation ofolefins. A portion of the steam required for the generation of olefinsin an olefin generating unit may be provided by steam present information fluid.

[1789] Alternatively, formation fluid may flow to a component removalunit prior to an olefin generating unit. In certain embodiments,formation fluid may include components containing small amounts of heavymetals such as arsenic, lead, and/or mercury. As depicted in FIG. 296,treatment unit 7290 may separate formation fluid 7010 into two componentstreams (e.g., streams 7292, 7294) and hydrocarbon containing fluids7296. Component streams 7292, 7294 may include a single component or amixture of multiple components. For example, treatment unit 7290 mayremove heavy metals in streams 7292, 7294. Hydrocarbon containing stream7296 may flow to olefin generating unit 7280 to be converted to olefinstream 7282. Olefin stream 7282 may include, but is not limited to,ethylene, propylene, and/or butylene.

[1790] Molecular hydrogen within an olefin feedstock may be removed fromthe olefin feedstock prior to the feedstock being provided to an olefingenerating unit in some embodiments. In alternate embodiments, formationfluid may flow to a hydrotreating unit prior to flowing to an olefingenerating unit to convert at least a portion of the olefin generatingcompounds into olefins.

[1791] In an olefin generating unit, a portion of the formation fluidmay be converted into compounds which may include, but are not limitedto, olefins, molecular hydrogen, pyrolysis gasoline that contains BTEXcompounds (benzene, toluene, ethylbenzene and/or xylene), pyrolysispitch, and/or butadiene. In some embodiments, the molecular hydrogengenerated in the olefin generating unit may flow to a hydrotreating unitto hydrotreat fluids. For example, a portion of the generated molecularhydrogen may be used to hydrotreat pyrolysis gasoline and/or pyrolysispitch generated in the olefin generating unit. Alternatively, a portionof the generated molecular hydrogen may be provided to an in situtreatment area.

[1792] In some embodiments, a portion of fluid generated in an olefingenerating unit may flow to one or more extraction units to removecomponents such as butadiene and/or BTEX compounds. In some embodiments,pyrolysis gasoline generated in an olefin generating unit may have ahigh BTEX content. Pyrolysis gasoline may, in certain embodiments, beprovided to a surface treatment unit to remove the BTEX compounds. Insome embodiments, pyrolysis pitch may be used as a fuel. Alternatively,pyrolysis pitch may be provided to an in situ treatment area foradditional processing.

[1793] A steam cracking unit may be utilized as an olefin generatingunit as depicted in FIG. 297. Steam cracking unit 7310 may includeheating unit 7320 and quenching unit 7330. Olefin feedstock 7300entering heating unit 7320 may be heated to a temperature greater thanabout 800° C. Fluid 7322 may flow to quenching unit 7330 to rapidlyquench and compress fluid 7322. Fluid 7332 exiting quenching unit 7330may include one or more olefin compounds, molecular hydrogen, and/orBTEX compounds. The olefin compounds may include, but are not limitedto, ethylene, propylene, and/or butylene. In certain embodiments, fluid7332 may flow to a separating unit. The components within fluid 7332 maybe separated into component streams in the separating unit. Thecomponent streams may be sold, transported to a different facility,stored for later use, and/or utilized on site in treatment areas or insurface treatment units.

[1794] Ammonia may be generated during an in situ conversion process. Insitu ammonia may be generated during a pyrolysis stage from some of thenitrogen present in hydrocarbon material. Hydrogen sulfide may also beproduced within the formation from some of the sulfur present in thehydrocarbon containing material. The ammonia and hydrogen sulfidegenerated in situ may be dissolved in water condensed from the formationfluids.

[1795]FIG. 298 depicts a configuration of surface treatment units thatmay separate ammonia and hydrogen sulfide from water produced in theformation. Formation fluid 7010 may be separated at wellhead 7012 intogas stream 7022, synthetic condensate 7015, and water stream 7026. Gastreating unit 7350 may separate gas stream 7022 into gas mixture 7352,light hydrocarbon mixture 7354, and/or hydrogen fraction 7356. Gasmixture 7352 may include, but is not limited to, hydrogen sulfide,carbon dioxide, and/or ammonia. Gas mixture 7352 may be blended withwater stream 7026 to form aqueous mixture 7358. Aqueous mixture 7358 mayflow to stripping unit 7360, where aqueous mixture 7358 is separatedinto ammonia stream 7362 and aqueous mixture 7364. Aqueous mixture 7364may flow to stripping unit 7370 to be separated into hydrogen sulfidestream 7372 and water stream 7374. Ammonia stream 7362 may be stored asan aqueous solution or in anhydrous form. Alternately, ammonia stream7362 may be provided to surface treatment units requiring ammonia, suchas a urea synthesis unit or an ammonium sulfate synthesis unit.

[1796] In some embodiments, ammonia may be formed from nitrogen presentin hydrocarbons when fluids are being hydrotreated. The generatedammonia may also be separated from other components, as illustrated inFIG. 299. Synthetic condensate 7015 may flow to hydrotreating unit 7380to form ammonia containing stream 7382 and hydrotreated syntheticcondensate 7384. Ammonia containing stream 7382 may be blended withwater stream 7026 and gas mixture 7352 prior to entering stripping unit7360 as aqueous mixture 7386.

[1797] Alternatively, fluid containing small amounts or concentrationsof ammonia may flow to Claus treatment unit 7390 for treatment, asdepicted in FIG. 300. Wellhead 7012 may separate formation fluid 7010into gas stream 7022, synthetic condensate 7015, and water stream 7026.Gas treating unit 7350 may further separate gas stream 7022 into gasmixture 7352, light hydrocarbon mixture 7354, and/or hydrogen fraction7356. Water stream 7026 and gas mixture 7352 may be blended to formstream 7358. Claus treatment unit 7390 may reduce ammonia in stream 7358to form fluid stream 7394. Recovered sulfur may exit Claus treatmentunit 7390 as sulfur stream 7392 and be utilized in any process thatrequires sulfur, either in surface facilities or treatment areas. Insome embodiments, Claus treatment unit 7390 may also generate a carbondioxide stream. The carbon dioxide may be utilized in a urea synthesisunit. Alternatively, carbon dioxide may be provided to an in situtreatment area for sequestration.

[1798] If a hydrotreating unit is used, then at least a portion of thesulfur in the stream entering the hydrotreating unit may be converted tohydrogen sulfide. In some embodiments, hydrogen sulfide may be used tomake fertilizer, sulfuric acid, and/or converted to sulfur in a Claustreatment unit. Similarly, some nitrogen in the stream entering thehydrotreating unit may be converted to ammonia, which may also berecovered for sale and/or use in processes.

[1799] In some embodiments, ammonia may be generated on site in surfacetreatment units using an ammonia synthesis process as shown in FIG. 301.Air stream 7400 may flow to air separating unit 7410 to separatenitrogen stream 7412 and stream 7414 from air stream 7400. Nitrogenstream 7412 may be heated with heat exchanger 7170 to form heatednitrogen feedstock 7416 prior to flowing into ammonia generating unit7420. Hydrogen feedstock 7418 may flow to ammonia generating unit 7420to react with nitrogen stream 7412 to form ammonia stream 7422. Ammoniagenerated during in situ or surface treatment processes may be stored inan aqueous solution or as anhydrous ammonia. In some instances, ammoniain either form may be sold commercially. Alternatively, ammonia may beused on site to generate a number of different products that havecommercial value (e.g., fertilizers such as ammonium sulfate and/orurea). Production of fertilizer may increase the economic viability of atreatment system used to treat a formation. Precursors for fertilizerproduction may be produced in situ or while treating formation fluid atsurface facilities.

[1800] Ammonia and carbon dioxide generated during treatment either insitu or at a surface treating unit may be used to generate urea for useas a fertilizer, as illustrated in FIG. 302. Ammonia stream 7424 andcarbon dioxide stream 7426 may react in urea generating unit 7428 toform urea stream 7430.

[1801] As illustrated in FIG. 303, ammonium sulfate may be generated bytreating formation fluid in a surface treatment unit. Wellhead 7012 mayseparate formation fluid 7010 into a mixture of non-condensablehydrocarbon fluids 7432 and synthetic condensate 7015. Separation unit7434 may be used to separate non-condensable hydrocarbon fluids 7432into hydrogen stream 7436, hydrogen sulfide stream 7438, methane stream7440, carbon dioxide stream 7442, and non-condensable hydrocarbon fluids7444.

[1802] Hydrogen sulfide stream 7438 may flow to oxidation unit 7446 tobe converted to sulfuric acid stream 7450. Additional hydrogen sulfidemay, in certain embodiments, be provided to oxidation unit 7446 fromhydrogen sulfide stream 7448. In some embodiments, hydrogen sulfidestream 7448 may be provided from a hydrotreating unit. The hydrotreatingunit may be a surface facility in a different section of a treatmentsystem or part of a different configuration of a treatment system.

[1803] Air separating unit 7410 may be used to separate nitrogen stream7412 and stream 7414 from air stream 7400. Heat exchanger 7170 may heatnitrogen stream 7412 to form heated nitrogen feedstock 7416. Hydrogenstream 7436 and heated nitrogen feedstock 7416 may flow to ammoniagenerating unit 7420 to form ammonia stream 7422. In some embodiments,additional hydrogen may be provided to ammonia generating unit 7420. Inalternate embodiments, a portion of hydrogen stream 7436 may flow to anin situ treatment area and/or a surface treatment facility. In certainembodiments, process ammonia 7452, produced in formation fluid and/orgenerated in surface treatment units, is added to ammonia stream 7422 toform ammonia feedstock 7454.

[1804] Ammonia feedstock 7454 and sulfuric acid stream 7450 may flowinto fertilizer synthesis unit 7456 to produce ammonium sulfate stream7458. Alternatively, a portion of sulfuric acid produced in an oxidationunit may be sold commercially.

[1805] In some embodiments, ammonia produced during treatment of aformation may be used to generate ammonium carbonate, ammoniumbicarbonate, ammonium carbamate, and/or urea. Separated ammonia may beprovided to a stream containing carbon dioxide (e.g., synthesis gasand/or carbon dioxide separated from formation fluid) such that theseparated ammonia reacts with carbon dioxide in the stream to generateammonium carbonate, ammonium bicarbonate, ammonium carbamate, and/orurea. Utilization of separated ammonia in this manner may reduce carbondioxide emissions from a treatment process. Ammonium carbonate, ammoniumbicarbonate, ammonium carbamate, and/or urea may be commerciallymarketed to a local market for use (e.g., as a fertilizer or a materialto make fertilizer). Ammonium carbonate, ammonium bicarbonate, ammoniumcarbamate, and/or urea may capture or sequester carbon dioxide ingeologic formations.

[1806] Formation fluid may include mono-aromatic components such asbenzene, toluene, ethyl benzene, and xylene, (i.e., BTEX compounds). Insome embodiments, separating BTEX compounds from formation fluid mayincrease an economic value of the generated products. Separated BTEXcompounds may have a higher economic value than the same BTEX compoundsin the mixture of component in the formation fluid. BTEX compounds maybe separated from a synthetic condensate stream. “Synthetic condensate”may refer to a liquid hydrocarbon condensate stream and/or ahydrotreated liquid condensate stream.

[1807] A process embodiment may include separating synthetic condensate7015 into BTEX compound stream 7472 and BTEX compound reduced syntheticcondensate 7474 using separating unit 7470, as illustrated in FIG. 304.Mono-aromatic reduced synthetic condensate 7474 may flow tohydrotreating unit 7476, where BTEX compound reduced syntheticcondensate 7474 is hydrotreated to form hydrotreated syntheticcondensate 7478. Hydrotreated synthetic condensate 7478 may flow to anysurface treatment unit for further treatment. Alternatively,mono-aromatic reduced synthetic condensate 7474 may, in certainembodiments, flow to a surface treatment unit for further treatment.

[1808] Mono-aromatic components, specifically BTEX compounds, may alsobe recovered after a synthetic condensate stream has been separated intoone or more fractions (e.g., a naphtha fraction, a jet fraction, and/ora diesel fraction). The naphtha fraction may be separated from formationfluid using a surface treatment unit. In some embodiments, removal ofBTEX compounds prior to hydrotreating the naphtha fraction may reducecapital and operating costs of a hydrotreating unit needed to treat thenaphtha fraction. In certain embodiments, a naphtha fraction may behydrotreated.

[1809] In some embodiments, formation fluid may contain BTEX generatingcompounds such as paraffins and/or naphthalene. BTEX generatingcompounds may flow to one or more surface treatment units to beconverted into BTEX compounds. In some embodiments, a syntheticcondensate may be hydrotreated and then separated in separating units toform a naphtha stream. The naphtha stream may be provided to a reformerunit that converts BTEX generating compounds to BTEX compounds.

[1810] Naphtha stream 7480 may flow to reforming unit 7482, asillustrated in FIG. 305. Naphtha stream 7480 may be converted intoreformate 7484 and hydrogen stream 7486. In certain embodiments,hydrogen stream 7486 flows to any surface treatment unit and/ortreatment area requiring hydrogen. For example, a hydrotreating unitand/or a reactive distillation column may utilize hydrogen stream 7486.Reformate 7484 may flow to recovery unit 7488. Reformate 7484 may beseparated into mono-aromatic stream 7492 and raffinate 7490 in recoveryunit 7488. In some embodiments, raffinate 7490 may flow to a processingunit to be converted to a gasoline stream. The gasoline may be providedto a local market. In alternate embodiments, a mono-aromatic recoveryunit may separate reformate 7484 into one or more streams, such asraffinate 7490, a benzene stream, a toluene stream, a ethyl benzenestream, and/or a xylene stream. In certain embodiments, naphtha stream7480 may be replaced with a “heart cut” (i.e., products distilled in arelatively narrow selected temperature range) corresponding tomono-aromatic compounds.

[1811] Conversion of BTEX generating compounds into BTEX compounds inreforming unit 7482 may form molecular hydrogen. The molecular hydrogenmay be used in one or more surface treatment units and/or in situtreatment areas where molecular hydrogen is needed. An advantage ofutilizing a reforming unit may be the generation of molecular hydrogenfor use on site. Generating molecular hydrogen on site may lower capitalas well as operating costs for a given treatment system.

[1812] Formation fluid produced from relatively permeable formationsduring an in situ conversion process may contain one or more components(e.g., naphthalene, anthracene, pyridine, pyrroles, and/or thiophene andits homologs). Various operating conditions within a treatment area maybe controlled to increase the production of a component. Some of thecomponents may be commercially viable products. Separating somecomponents from formation fluid may increase the total value ofgenerated products. A separated component in relatively concentratedform may have higher economic value than the same component in formationfluid. For example, formation fluid containing naphthalene may be soldat a lower price than a naphthalene stream separated from the formationfluid and the remaining formation fluid. In an embodiment, separation ofnaphthalenes may be accomplished using crystallization. In addition,removal of some components may reduce hydrogen consumption in subsequenthydrotreating units.

[1813]FIG. 306 depicts an embodiment of recovery unit 7496 used toseparate a component from heart cut 7494. Heart cut 7494 may be obtainedfrom a synthetic crude or formation fluid. Heart cut 7494 flows torecovery unit 7496, which may separate heart cut 7494 into componentstream 7498 and hydrocarbon mixture 7450. In some embodiments, componentstream 7498 may be sold and/or used on site in an in situ treatment areaand/or a surface treatment unit. Hydrocarbon mixture 7450 may flow toone or more treatment units for additional treatment or, in someembodiments, to an in situ treatment area.

[1814] In some embodiments, the recovery unit, as shown in FIG. 306,separates the component from a feedstock stream (e.g., formation fluid,synthetic condensate, a gas stream, a light fraction, a middle fraction,a heavy fraction, bottoms, a naphtha stream, a jet fuel stream, a dieselstream, etc). Recovery units may separate more than one component fromthe feedstock stream in certain embodiments. For example, a recoveryunit may separate a feedstock stream into a naphthalene stream, ananthracene stream, a naphthalene/anthracene stream, and/or a hydrocarbonmixture. Fluids generated during an in situ conversion process maycontain naphthalene and/or anthracene.

[1815] When nitrogen containing components (e.g., pyridines andpyrroles) are to be separated from a feedstock, the recovery unit may bea nitrogen extraction unit. In some embodiments, a nitrogen extractionunit may separate the nitrogen containing components using a sulfuricacid process or a formic acid process. Nitrogen extraction units mayinclude sulfuric acid extraction units and/or closed cycle formic acidextraction units. A sulfuric acid process may separate a portion of theformation fluid into a raffinate and an extract oil. The extract oil maycontain pyridines and other nitrogen containing compounds, as well asspent acid. The extract oil may be separated into a nitrogen richextract and an acid stream.

[1816] A successful extraction process exhibits the followingproperties: inhibition of emulsion formation, immiscibility with thefeedstock, rapid phase separation, and high capacity.

[1817]FIG. 307 depicts an embodiment of treatment areas 8000 surroundedby perimeter barrier 8002. Each treatment area 8000 may be a volume offormation that is, or is to be, subjected to an in situ conversionprocess. Perimeter barrier 8002 may include installed portions andnaturally occurring portions of the formation. Naturally occurringportions of the formation that form part of a perimeter barrier mayinclude substantially impermeable layers of the formation. Examples ofnaturally occurring perimeter barriers include overburdens andunderburdens. Installed portions of perimeter barrier 8002 may be formedas needed to define separate treatment areas 8000. In situ conversionprocess (ICP) wells 8004 may be placed within treatment areas 8000. ICPwells 8004 may include heat sources, production wells, treatment areadewatering wells, monitor wells, and other types of wells used during insitu conversion.

[1818] Different treatment areas 8000 may share common barrier sectionsto minimize the length of perimeter barrier 8002 that needs to beformed. Perimeter barrier 8002 may inhibit fluid migration intotreatment area 8000 undergoing in situ conversion. Advantageously,perimeter barrier 8002 may inhibit formation water from migrating intotreatment area 8000. Formation water typically includes water anddissolved material in the water (e.g., salts). If formation water wereallowed to migrate into treatment area 8000 during an in situ conversionprocess, the formation water might increase operating costs for theprocess by adding additional energy costs associated with vaporizing theformation water and additional fluid treatment costs associated withremoving, separating, and treating additional water in formation fluidproduced from the formation. A large amount of formation water migratinginto a treatment area may inhibit heat sources from raising temperatureswithin portions of treatment area 8000 to desired temperatures.

[1819] Perimeter barrier 8002 may inhibit undesired migration offormation fluids out of treatment area 8000 during an in situ conversionprocess. Perimeter barriers 8002 between adjacent treatment areas 8000may allow adjacent treatment areas to undergo different in situconversion processes. For example, a first treatment area may beundergoing pyrolysis, a second treatment area adjacent to the firsttreatment area may be undergoing synthesis gas generation, and a thirdtreatment area adjacent to the first treatment area and/or the secondtreatment area may be subjected to an in situ solution mining process.Operating conditions within the different treatment areas may be atdifferent temperatures, pressures, production rates, heat injectionrates, etc.

[1820] Perimeter barrier 8002 may define a limited volume of formationthat is to be treated by an in situ conversion process. The limitedvolume of formation is known as treatment area 8000. Defining a limitedvolume of formation that is to be treated may allow operating conditionswithin the limited volume to be more readily controlled. In someformations, a hydrocarbon containing layer that is to be subjected to insitu conversion is located in a portion of the formation that ispermeable and/or fractured. Without perimeter barrier 8002, formationfluid produced during in situ conversion might migrate out of the volumeof formation being treated. Flow of formation fluid out of the volume offormation being treated may inhibit the ability to maintain a desiredpressure within the portion of the formation being treated. Thus,defining a limited volume of formation that is to be treated by usingperimeter barrier 8002 may allow the pressure within the limited volumeto be controlled. Controlling the amount of fluid removed from treatmentarea 8000 through pressure relief wells, production wells and/or heatsources may allow pressure within the treatment area to be controlled.In some embodiments, pressure relief wells are perforated casings placedwithin or adjacent to wellbores of heat sources that have sealedcasings, such as flameless distributed combustors. The use of some typesof perimeter barriers (e.g., frozen barriers and grout walls) may allowpressure control in individual treatment areas 8000.

[1821] Uncontrolled flow or migration of formation fluid out oftreatment area 8000 may adversely affect the ability to efficientlymaintain a desired temperature within treatment area 8000. Perimeterbarrier 8002 may inhibit migration of hot formation fluid out oftreatment area 8000. Inhibiting fluid migration through the perimeter oftreatment area 8000 may limit convective heat losses to heat loss influid removed from the formation through production wells and/or fluidremoved to control pressure within the treatment area.

[1822] During in situ conversion, heat applied to the formation maycause fractures to develop within treatment area 8000. Some of thefractures may propagate towards a perimeter of treatment area 8000. Apropagating fracture may intersect an aquifer and allow formation waterto enter treatment area 8000. Formation water entering treatment area8000 may not permit heat sources in a portion of the treatment area toraise the temperature of the formation to temperatures significantlyabove the vaporization temperature of formation water entering theformation. Fractures may also allow formation fluid produced during insitu conversion to migrate away from treatment area 8000.

[1823] Perimeter barrier 8002 around treatment area 8000 may limit theeffect of a propagating fracture on an in situ conversion process. Insome embodiments, perimeter barriers 8002 are located far enough awayfrom treatment areas 8000 so that fractures that develop in theformation do not influence perimeter barrier integrity. Perimeterbarriers 8002 may be located over 10 m, 40 m, or 70 m away from ICPwells 8004. In some embodiments, perimeter barrier 8002 may be locatedadjacent to treatment area 8000. For example, a frozen barrier formed byfreeze wells may be located close to heat sources, production wells, orother wells. ICP wells 8004 may be located less than 1 m away fromfreeze wells, although a larger spacing may advantageously limitinfluence of the frozen barrier on the ICP wells, and limit theinfluence of formation heating on the frozen barrier.

[1824] In some perimeter barrier embodiments, and especially for naturalperimeter barriers, ICP wells 8004 may be placed in perimeter barrier8002 or next to the perimeter barrier. For example, ICP wells 8004 maybe used to treat hydrocarbon layer 516 that is a thin rich hydrocarbonlayer. The ICP wells may be placed in overburden 540 and/or underburden8010 adjacent to hydrocarbon layer 516, as depicted in FIG. 308. ICPwells 8004 may include heater-production wells that heat the formationand remove fluid from the formation. Thin rich layer hydrocarbon layer516 may have a thickness greater than about 0.2 m and less than about 8m, and a richness of from about 205 liters of oil per metric ton toabout 1670 liters of oil per metric ton. Overburden 540 and underburden8010 may be portions of perimeter barrier 8002 for the in situconversion system used to treat rich thin layer 516. Heat losses tooverburden 540 and/or underburden 8010 may be acceptable to produce richhydrocarbon layer 516. In other ICP well placement embodiments fortreating thin rich hydrocarbon layers 516, ICP wells 8004 may be placedwithin hydrocarbon layer 516, as depicted in FIG. 309.

[1825] In some in situ conversion process embodiments, a perimeterbarrier may be self-sealing. For example, formation water adjacent to afrozen barrier formed by freeze wells may freeze and seal the frozenbarrier should the frozen barrier be ruptured by a shift or fracture inthe formation. In some in situ conversion process embodiments, progressof fractures in the formation may be monitored. If a fracture that ispropagating towards the perimeter of the treatment area is detected, acontrollable parameter (e.g., pressure or energy input) may be adjustedto inhibit propagation of the fracture to the surrounding perimeterbarrier.

[1826] Perimeter barriers may be useful to address regulatory issuesand/or to insure that areas proximate a treatment area (e.g., watertables or other environmentally sensitive areas) are not substantiallyaffected by an in situ conversion process. The formation within theperimeter barrier may be treated using an in situ conversion process.The perimeter barrier may inhibit the formation on an outer side of theperimeter barrier from being affected by the in situ conversion processused on the formation within the perimeter barrier. Perimeter barriersmay inhibit fluid migration from a treatment area. Perimeter barriersmay inhibit rise in temperature to pyrolysis temperatures on outer sidesof the perimeter barriers.

[1827] Different types of barriers may be used to form a perimeterbarrier around an in situ conversion process treatment area. Theperimeter barrier may be, but is not limited to, a frozen barriersurrounding the treatment area, dewatering wells, a grout wall formed inthe formation, a sulfur cement barrier, a barrier formed by a gelproduced in the formation, a barrier formed by precipitation of salts inthe formation, a barrier formed by a polymerization reaction in theformation, sheets driven into the formation, or combinations thereof.

[1828]FIG. 310 depicts a side representation of a portion of anembodiment of treatment area 8000 having perimeter barrier 8002 formedby overburden 540, underburden 8010, and freeze wells 8012 (only onefreeze well is shown in FIG. 310). A portion of freeze well 8012 andperimeter barrier 8002 formed by the freeze well extend into underburden8010. In some embodiments, perimeter barrier 8002 may not extend intounderburden 8010 (e.g., a perimeter barrier may extend into hydrocarbonlayer 516 reasonably close to the underburden or some of the hydrocarbonlayer may function as part of the perimeter barrier). Underburden 8010may be a rock layer that inhibits fluid flow into or out of treatmentarea 8000. In some embodiments, a portion of the underburden may behydrocarbon containing material that is not to be subjected to in situconversion.

[1829] Overburden 540 may extend over treatment area 8000. Overburden540 may include a portion of hydrocarbon containing material that is notto be subjected to in situ conversion. Overburden 540 may inhibit fluidflow into or out of treatment area 8000.

[1830] Some formations may include underburden 8010 that is permeable orincludes fractures that would allow fluid flow into or out of treatmentarea 8000. A portion of perimeter barrier 8002 may be formed belowtreatment area 8000 to inhibit inflow of fluid into the treatment areaand/or to inhibit outflow of formation fluid during in situ conversion.FIG. 311 depicts treatment area 8000 having a portion of perimeterbarrier 8002 that is below the treatment area. The perimeter barrier maybe a frozen barrier formed by freeze wells 8012. In some embodiments, aperimeter barrier below a treatment area may follow along a geologicalformation (e.g., along dip).

[1831] Some formations may include overburden 540 that is permeable orincludes fractures that allow fluid flow into or out of treatment area8000. A portion of perimeter barrier 8002 may be formed above thetreatment area to inhibit inflow of fluid into the treatment area and/orto inhibit outflow of formation fluid during in situ conversion. FIG.311 depicts an embodiment of an in situ conversion process having aportion of perimeter barrier 8002 formed above treatment area 8000. Insome embodiments, a perimeter barrier above a treatment area may followalong a geological formation (e.g., along dip of a dipping formation).In some embodiments, a perimeter barrier above a treatment area may beformed as a ground cover placed at or near the surface of the formation.Such a perimeter barrier may allow for treatment of a formation whereina hydrocarbon layer to be processed is close to the surface.

[1832] As depicted in FIG. 307, several perimeter barriers 8002 may beformed to divide a formation into treatment areas 8000. If a largeamount of water is present in the hydrocarbon containing material,dewatering wells may be used to remove water in the treatment area aftera perimeter barrier is formed. If the hydrocarbon containing materialdoes not contain a large amount of water, heat sources may be activated.The heat sources may vaporize water within the formation, and the watervapor may be removed from the treatment area through production wells.

[1833] A perimeter barrier may have any desired shape. In someembodiments, portions of perimeter barriers may follow along geologicalfeatures and/or property lines. In some embodiments, portions ofperimeter barriers may have circular, square, rectangular, or polygonalshapes. Portions of perimeter barriers may also have irregular shapes. Aperimeter barrier having a circular shape may advantageously enclose alarger area than other regular polygonal shapes that have the sameperimeter. For example, for equal perimeters, a circular barrier willenclose about 27% more area than a square barrier. Using a circularperimeter barrier may require fewer wells and/or less material toenclose a desired area with a perimeter barrier than would other regularperimeter barrier shapes. In some embodiments, square, rectangular orother polygonal perimeter barriers are used to conform to property linesand/or to accommodate a regular well pattern of heat sources andproduction wells.

[1834] A formation that is to be treated using an in situ conversionprocess may be separated into several treatment areas by perimeterbarriers. FIG. 307 depicts an embodiment of a perimeter barrierarrangement for a portion of a formation that is to be processed usingsubstantially rectangular treatment areas 8000. A perimeter barrier fortreatment area 8000 may be formed when needed. The complete pattern ofperimeter barriers for all of the formation to be subjected to in situconversion does not need to be formed prior to treating individualtreatment areas.

[1835] Perimeter barriers having circular or arced portions may beplaced in a formation in a regular pattern. Centers of the circular orarced portions may be positioned at apices of imaginary polygonpatterns. For example, FIG. 312 depicts a pattern of perimeter barrierswherein a unit of the pattern is based on an equilateral triangle. FIG.313 depicts a pattern of perimeter barriers wherein a unit of thepattern is based on a square. Perimeter barrier patterns may also bebased on higher order polygons.

[1836]FIG. 312 depicts a plan view representation of a perimeter barrierembodiment that forms treatment areas 8000 in a formation. Centers ofarced portions of perimeter barriers 8002 are positioned at apices ofimaginary equilateral triangles. The imaginary equilateral triangles aredepicted as dashed lines. First circular barrier 8002′ may be formed inthe formation to define first treatment area 8000′.

[1837] Second barrier 8002″ may be formed. Second barrier 8002″ andportions of first barrier 8002′ may define second treatment area 8000″.Second barrier 8002″ may have an arced portion with a radius that issubstantially equal to the radius of first circular barrier 8002′. Thecenter of second barrier 8002″ may be located such that if the secondbarrier were formed as a complete circle, the second barrier wouldcontact the first barrier substantially at a tangent point. Secondbarrier 8002″ may include linear sections 8014 that allow for a largerarea to be enclosed for the same or a lesser length of perimeter barrierthan would be needed to complete the second barrier as a circle. In someembodiments, second barrier 8002″ may not include linear sections andthe second barrier may contact the first barrier at a tangent point orat a tangent region. Second treatment area 8000″ may be defined byportions of first circular barrier 8002′ and second barrier 8002″. Thearea of second treatment area 8000″ may be larger than the area of firsttreatment area 8000′.

[1838] Third barrier 8002′″ may be formed adjacent to first barrier8002′ and second barrier 8002″. Third barrier 8002′″ may be connected tofirst barrier 8002′ and second barrier 8002″ to define third treatmentarea 8000′″. Additional barriers may be formed to form treatment areasfor processing desired portions of a formation.

[1839]FIG. 313 depicts a plan view representation of a perimeter barrierembodiment that forms treatment areas 8000 in a formation. Centers ofarced portions of perimeter barriers 8002 are positioned at apices ofimaginary squares. The imaginary squares are depicted as dashed lines.First circular barrier 8002′ may be formed in the formation to definefirst treatment area 8000′. Second barrier 8002″ may be formed around aportion of second treatment area 8000″. Second barrier 8002″ may have anarced portion with a radius that is substantially equal to the radius offirst circular barrier 8002′. The center of second barrier 8002″ may belocated such that if the second barrier were formed as a completecircle, the second barrier would contact the first barrier at a tangentpoint. Second barrier 8002″ may include linear sections 8014 that allowfor a larger area to be enclosed for the same or a lesser length ofperimeter barrier than would be needed to complete the second barrier asa circle. Two additional perimeter barriers may be formed to complete aunit of four treatment areas.

[1840] In some embodiments, central area 8016 may be isolated byperimeter barrier 8002. For perimeter barriers based on a squarepattern, such as the perimeter barriers depicted in FIG. 313, centralarea 8016 may be a square. A length of a side of the square may be up toabout 0.586 times a radius of an arc section of a perimeter barrier.Surface facilities, or a portion of the surface facilities, used totreat fluid removed from the formation may be located in central area8016. In other embodiments, perimeter barrier segments that form acentral area may not be installed.

[1841]FIG. 314 depicts an embodiment of a barrier configuration in whichperimeter barriers 8002 are formed radially about a central point. In anembodiment, surface facilities for processing production fluid removedfrom the formation are located within central area 8016 defined by firstbarrier 8002′. Locating the surface facilities in the center may reducethe total length of piping needed to transport formation fluid to thetreatment facilities. In alternate embodiments, ICP wells are installedin the central area and surface facilities are located outside of thepattern of barriers.

[1842] A ring of formation between second barrier 8002″ and firstbarrier 8002′ may be treatment area 8000′. Third barrier 8002′″ may beformed around second barrier 8002″. The pattern of barriers may beextended as needed. A ring of formation between an inner barrier and anouter barrier may be a treatment area. If the area of a ring is toolarge to be treated as a whole, linear sections 8014 extending from theinner barrier to the outer barrier may be formed to divide the ring intoa number of treatment areas. In some embodiments, distances betweenbarrier rings may be substantially the same. In other embodiments, adistance between barrier rings may be varied to adjust the area enclosedby the barriers.

[1843] In some embodiments of in situ conversion processes, formationwater may be removed from a treatment area before, during, and/or afterformation of a barrier around the formation. Heat sources, productionwells, and other ICP wells may be installed in the formation before,during, or after formation of the barrier. Some of the production wellsmay be coupled to pumps that remove formation water from the treatmentarea. In other embodiments, dewatering wells may be formed within thetreatment area to remove formation water from the treatment area.Removing formation water from the treatment area prior to heating topyrolysis temperatures for in situ conversion may reduce the energyneeded to raise portions of the formation within the treatment area topyrolysis temperatures by eliminating the need to vaporize all formationwater initially within the treatment area.

[1844] In some embodiments of in situ conversion processes, freeze wellsmay be used to form a low temperature zone around a portion of atreatment area. “Freeze well” refers to a well or opening in a formationused to cool a portion of the formation. In some embodiments, thecooling may be sufficient to cause freezing of materials (e.g.,formation water) that may be present in the formation. In otherembodiments, the cooling may not cause freezing to occur; however, thecooling may serve to inhibit the flow of fluid into or out of atreatment area by filling a portion of the pore space with liquid fluid.

[1845] In some embodiments, freeze wells may be used to form a sideperimeter barrier, or a portion of a side perimeter barrier, in aformation. In some embodiments, freeze wells may be used to form abottom perimeter barrier, or a portion of a bottom perimeter barrier,underneath a formation. In some embodiments, freeze wells may be used toform a top perimeter barrier, or a portion of a top perimeter barrier,above a formation.

[1846] In some embodiments, freeze wells may be maintained attemperatures significantly colder than a freezing temperature offormation water. Heat may transfer from the formation to the freezewells so that a low temperature zone is formed around the freeze wells.A portion of formation water that is in, or flows into, the lowtemperature zone may freeze to form a barrier to fluid flow. Freezewells may be spaced and operated so that the low temperature zone formedby each freeze well overlaps and connects with a low temperature zoneformed by at least one adjacent freeze well.

[1847] Sections of freeze wells that are able to form low temperaturezones may be only a portion of the overall length of the freeze wells.For example, a portion of each freeze well may be insulated adjacent toan overburden so that heat transfer between the freeze wells and theoverburden is inhibited. The freeze wells may form a low temperaturezone along sides of a hydrocarbon containing portion of the formation.The low temperature zone may extend above and/or below a portion of thehydrocarbon containing layer to be treated by in situ conversion. Theability to use only portions of freeze wells to form a low temperaturezone may allow for economic use of freeze wells when forming barriersfor treatment areas that are relatively deep within the formation.

[1848] A perimeter barrier formed by freeze wells may have severaladvantages over perimeter barriers formed by other methods. A perimeterbarrier formed by freeze wells may be formed deep within the ground. Aperimeter barrier formed by freeze wells may not require aninterconnected opening around the perimeter of a treatment area. Aninterconnected opening is typically needed for grout walls and someother types of perimeter barriers. A perimeter barrier formed by freezewells develops due to heat transfer, not by mass transfer. Gel, polymer,and some other types of perimeter barriers depend on mass transferwithin the formation to form the perimeter barrier. Heat transfer in aformation may vary throughout a formation by a relatively small amount(e.g., typically by less than a factor of 2 within a formation layer).Mass transfer in a formation may vary by a much greater amountthroughout a formation (e.g., by a factor of 10⁸ or more within aformation layer). A perimeter barrier formed by freeze wells may havegreater integrity and be easier to form and maintain than a perimeterbarrier that needs mass transfer to form.

[1849] A perimeter barrier formed by freeze wells may provide a thermalbarrier between different treatment areas and between surroundingportions of the formation that are to remain untreated. The thermalbarrier may allow adjacent treatment areas to be subjected to differentprocesses. The treatment areas may be operated at different pressures,temperatures, heating rates, and/or formation fluid removal rates. Thethermal barrier may inhibit hydrocarbon material on an outer side of thebarrier from being pyrolyzed when the treatment area is heated.

[1850] Forming a frozen perimeter barrier around a treatment area withfreeze wells may be more economical and beneficial over the life of anin situ conversion process than operating dewatering wells around thetreatment area. Freeze wells may be less expensive to install, operate,and maintain than dewatering wells. Casings for dewatering wells mayneed to be formed of corrosion resistant metals to withstand corrosionfrom formation water over the life of an in situ conversion process.Freeze wells may be made of carbon steel. Dewatering wells may enhancethe spread of formation fluid from a treatment area. Water produced fromdewatering wells may contain a portion of formation fluid. Such watermay need to be treated to remove hydrocarbons and other material beforethe water can be released. Dewatering wells may inhibit the ability toraise pressure within a treatment area to a desired value sincedewatering wells are constantly removing fluid from the formation.

[1851] Water presence in a low temperature zone may allow for theformation of a frozen barrier. The frozen barrier may be a monolithic,impermeable structure. After the frozen barrier is established, theenergy requirements needed to maintain the frozen barrier may besignificantly reduced, as compared to the energy costs needed toestablish the frozen barrier. In some embodiments, the reduction in costmay be a factor of 10 or more. In other embodiments, the reduction incost may be less dramatic, such as a reduction by a factor of about 3 or4.

[1852] In many formations, hydrocarbon containing portions of theformation are saturated or contain sufficient amounts of formation waterto allow for formation of a frozen barrier. In some formations, watermay be added to the formation adjacent to freeze wells after and/orduring formation of a low temperature zone so that a frozen barrier willbe formed.

[1853] In some in situ conversion embodiments, a low temperature zonemay be formed around a treatment area. During heating of the treatmentarea, water may be released from the treatment area as steam and/orentrained water in formation fluids. In general, when a treatment areais initially heated, water present in the formation is mobilized beforesubstantial quantities of hydrocarbons are produced. The water may befree water and/or released water that was attached or bound to clays orminerals (“bound water”). Mobilized water may flow into the lowtemperature zone. The water may condense and subsequently solidify inthe low temperature zone to form a frozen barrier.

[1854] Pyrolyzing hydrocarbons and/or oxidizing hydrocarbons may formwater vapor during in situ conversion. A significant portion of thegenerated water vapor may be removed from the formation throughproduction wells. A small portion of the generated water vapor maymigrate towards the perimeter of the treatment area. As the waterapproaches the low temperature zone formed by the freeze wells, aportion of the water may condense to liquid water in the low temperaturezone. If the low temperature zone is cold enough, or if the liquid watermoves into a cold enough portion of the low temperature zone, the watermay solidify.

[1855] In some embodiments, freeze wells may form a low temperature zonethat does not result in solidification of formation fluid. For example,if there is insufficient water or other fluid with a relatively highfreezing point in the formation around the freeze wells, then the freezewells may not form a frozen barrier. Instead, a low temperature zone maybe formed. During an in situ conversion process, formation fluid maymigrate into the low temperature zone. A portion of formation fluid(e.g., low freezing point hydrocarbons) may condense in the lowtemperature zone. The condensed fluid may fill pore space within the lowtemperature zone. The condensed fluid may form a barrier to additionalfluid flow into or out of the low temperature zone. A portion of theformation fluid (e.g., water vapor) may condense and freeze within thelow temperature zone to form a frozen barrier. Condensed formation fluidand/or solidified formation fluid may form a barrier to further fluidflow into or out of the low temperature zone.

[1856] Freeze wells may be initiated a significant time in advance ofinitiation of heat sources that will heat a treatment area. Initiatingfreeze wells in advance of heat source initiation may allow for theformation of a thick interconnected frozen perimeter barrier beforeformation temperature in a treatment area is raised. In someembodiments, heat sources that are located a large distance away from aperimeter of a treatment area may be initiated before, simultaneouslywith, or shortly after initiation of freeze wells.

[1857] Heat sources may not be able to break through a frozen perimeterbarrier during thermal treatment of a treatment area. In someembodiments, a frozen perimeter barrier may continue to expand for asignificant time after heating is initiated. Thermal diffusivity of ahot, dry formation may be significantly smaller than thermal diffusivityof a frozen formation. The difference in thermal diffusivities betweenhot, dry formation and frozen formation implies that a cold zone willexpand at a faster rate than a hot zone. Even if heat sources are placedrelatively close to freeze wells that have formed a frozen barrier(e.g., about 1 m away from freeze wells that have established a frozenbarrier), the heat sources will typically not be able to break throughthe frozen barrier if coolant is supplied to the freeze wells. Incertain ICP system embodiments, freeze wells are positioned asignificant distance away from the heat sources and other ICP wells. Thedistance may be about 3 m, 5 m, 10 m, 15 m, or greater.

[1858] The frozen barrier formed by the freeze wells may expand on anoutward side of the perimeter barrier even when heat sources heat theformation on an inward side of the perimeter barrier.

[1859]FIG. 307 depicts a representation of freeze wells 8012 installedin a formation to form low temperature zones 8017 around treatment areas8000. Fluid in low temperature zones 8017 with a freezing point above atemperature of the low temperature zones may solidify in the lowtemperature zones to form perimeter barrier 8002. Typically, the fluidthat solidifies to form perimeter barrier 8002 will be a portion offormation water. Two or more rows of freeze wells may be installedaround treatment area 8000 to form a thicker low temperature zone 8017than can be formed using a single row of freeze wells. FIG. 315 depictstwo rows of freeze wells 8012 around treatment area 8000. Freeze wells8012 may be placed around all of treatment area 8000, or freeze wellsmay be placed around a portion of the treatment area. In someembodiments, natural fluid flow barriers (such as unfractured,substantially impermeable formation material) and/or artificial barriers(e.g., grout walls or interconnected sheet barriers) surround remainingportions of the treatment area when freeze wells do not surround all ofthe treatment area.

[1860] If more than one row of freeze wells surrounds a treatment area,the wells in a first row may be staggered relative to wells in a secondrow. In the freeze well arrangement embodiment depicted in FIG. 315,first separation distance 8018 exists between freeze wells 8012 in a rowof freeze wells. Second separation distance 8020 exists between freezewells 8012 in a first row and a second row. Second separation distance8020 may be about 10-75% (e.g., 30-60% or 50%) of first separationdistance 8018. Other separation distances and freeze well patterns mayalso be used.

[1861]FIG. 311 depicts an embodiment of an ICP system with freeze wells8012 that form low temperature zone 8017 below a portion of a formation,a low temperature zone above a portion of a formation, and a lowtemperature zone along a perimeter of a portion of the formation.Portions of heat sources 8022 and portions of production wells 8024 maypass through low temperature zone 8017 formed by freeze wells 8012. Theportions of heat sources 8022 and production wells 8024 that passthrough low temperature zone 8017 may be insulated to inhibit heattransfer to the low temperature zone. The insulation may include, but isnot limited to, foamed cement, an air gap between an insulated linerplaced in the production well, or a combination thereof.

[1862] A portion of a freeze well that is to form a low temperature zonein a formation may be placed in the formation in desired spaced relationto an adjacent freeze well or freeze wells so that low temperature zonesformed by the individual freeze wells interconnect to form a continuouslow temperature zone. In some freeze well embodiments, each freeze wellmay have two or more sections that allow for heat transfer with anadjacent formation. Other sections of the freeze wells may be insulatedto inhibit heat transfer with the adjacent formation.

[1863] Freeze wells may be placed in the formation so that there isminimal deviation in orientation of one freeze well relative to anadjacent freeze well. Excessive deviation may create a large separationdistance between adjacent freeze wells that may not permit formation ofan interconnected low temperature zone between the adjacent freezewells. Factors that may influence the manner in which freeze wells areinserted into the ground include, but are not limited to, freeze wellinsertion time, depth that the freeze wells are to be inserted,formation properties, desired well orientation, and economics.Relatively low depth freeze wells may be impacted and/or vibrationallyinserted into some formations. Freeze wells may be impacted and/orvibrationally inserted into formations to depths from about 1 m to about100 m without excessive deviation in orientation of freeze wellsrelative to adjacent freeze wells in some types of formations. Freezewells placed deep in a formation or in formations with layers that aredifficult to drill through may be placed in the formation by directionaldrilling and/or geosteering. Directional drilling with steerable motorsuses an inclinometer to guide the drilling assembly. Periodic gyro logsare obtained to correct the path. An example of a directional drillingsystem is VertiTrak™ available from Baker Hughes Inteq (Houston, Tex.).Geosteering uses analysis of geological and survey data from an activelydrilling well to estimate stratigraphic and structural position neededto keep the wellbore advancing in a desired direction. Electrical,magnetic, and/or other signals produced in an adjacent freeze well mayalso be used to guide directionally drilled wells so that a desiredspacing between adjacent wells is maintained. Relatively tight controlof the spacing between freeze wells is an important factor in minimizingthe time for completion of a low temperature zone.

[1864]FIG. 316 depicts a representation of an embodiment of freeze well8012 that is directionally drilled into a formation. Freeze well 8012may enter the formation at a first location and exit the formation at asecond location so that both ends of the freeze well are above theground surface. Refrigerant flow through freeze well 8012 may reduce thetemperature of the formation adjacent to the freeze well to form lowtemperature zone 8017. Refrigerant passing through freeze well 8012 maybe passed through an adjacent freeze well or freeze wells. Temperatureof the refrigerant may be monitored. When the refrigerant temperatureexceeds a desired value, the refrigerant may be directed to arefrigeration unit or units to reduce the temperature of the refrigerantbefore recycling the refrigerant back into the freeze wells. The use offreeze wells that both enter and exit the formation may eliminate theneed to accommodate an inlet refrigerant passage and an outletrefrigerant passage in each freeze well.

[1865] Freeze well 8012 depicted in the embodiment of FIG. 316 formspart of frozen barrier 8002 below water body 8026. Water body 8026 maybe any type of water body such as a pond, lake, stream, or river. Insome embodiments, the water body may be a subsurface water body such asan underground stream or river. Freeze well 8012 is one of many freezewells that may inhibit downward migration of water from water body 8026to hydrocarbon containing layer 516.

[1866]FIG. 317 depicts a representation of freeze wells 8012 used toform a low temperature zone on a side of hydrocarbon containing layer516. In some embodiments, freeze wells 8012 may be placed in anon-hydrocarbon containing layer that is adjacent to hydrocarboncontaining layer 516. In the depicted embodiment, freeze wells 8012 areoriented along dip of hydrocarbon containing layer 516. In someembodiments, freeze wells may be inserted into the formation from twodifferent directions or substantially perpendicular to the groundsurface to limit the length of the freeze wells. Freeze well 8012′ andother freeze wells may be inserted into hydrocarbon containing layer 516to form a perimeter barrier that inhibits fluid flow along thehydrocarbon containing layer. If needed, additional freeze wells may beinstalled to form perimeter barriers to inhibit fluid flow into or fromoverburden 540 or underburden 8010.

[1867] As depicted in FIG. 310, freeze wells 8012 may be positionedwithin a portion of a formation. Freeze wells 8012 and ICP wells mayextend through overburden 540, through hydrocarbon layer 516, and intounderburden 8010. In some embodiments, portions of freeze wells and ICPwells extending through the overburden 540 may be insulated to inhibitheat transfer to or from the surrounding formation.

[1868] In some embodiments, dewatering wells 8028 may extend intoformation 516. Dewatering wells 8028 may be used to remove formationwater from hydrocarbon containing layer 516 after freeze wells 8012 formperimeter barrier 8002. Water may flow through hydrocarbon containinglayer 516 in an existing fracture system and channels. Only a smallnumber of dewatering wells 8028 may be needed to dewater treatment area8000 because the formation may have a large permeability due to theexisting fracture system and channels. Dewatering wells 8028 may beplaced relatively close to freeze wells 8012. In some embodiments,dewatering wells may be temporarily sealed after dewatering. Ifdewatering wells are placed close to freeze wells or to a lowtemperature zone formed by freeze wells, the dewatering wells may befilled with water. Expanding low temperature zone 8017 may freeze thewater placed in the freeze wells to seal the freeze wells. Dewateringwells 8028 may be re-opened after completion of in situ conversion.After in situ conversion, dewatering wells 8028 may be used during cleanup procedures for injection or removal of fluids.

[1869] In some embodiments, selected production wells, heat sources, orother types of ICP wells may be temporarily converted to dewateringwells by attaching pumps to the selected wells. The converted wells maysupplement dewatering wells or eliminate the need for separatedewatering wells. Converting other wells to dewatering wells mayeliminate costs associated with drilling wellbores for dewatering wells.

[1870]FIG. 318 depicts a representation of an embodiment of a wellsystem for treating a formation. Hydrocarbon containing layer 516 mayinclude leached/fractured portion 8030 and non-leached/non-fracturedportion 8032. Formation water may flow through leached/fractured portion8030. Non-leached/non-fractured portion 8032 may be unsaturated andrelatively dry. In some formations, leached/fractured portion 8030 maybe beneath 100 m or more of overburden 540, and the leached/fracturedportion may extend 200 m or more into the formation.Non-leached/non-fractured portion 8032 may extend 400 m or more deeperinto the formation.

[1871] Heat sources 8022 may extend to underburden 8010 belownon-leached/non-fractured portion 8032. Production wells may extend intothe non-leached/non-fractured portion of the formation. The productionwells may have perforations, or be open wellbores, along the portionsextending into the leached/fractured portion andnon-leached/non-fractured portions of the hydrocarbon containing layer.Freeze wells 8012 may extend close to, or a short distance into,non-leached/non-fractured portion 8032. Freeze wells 8012 may be offsetfrom heat sources 8022 and production wells a distance sufficient toallow hydrocarbon material below the freeze wells to remain unpyrolyzedduring treatment of the formation (e.g., about 30 m). Freeze wells 8012may inhibit formation water from flowing into hydrocarbon containinglayer 516. Advantageously, freeze wells 8012 do not need to extend alongthe full length of hydrocarbon material that is to be subjected to insitu conversion, because non-leached/non-fractured portion 8032 beneathfreeze wells 8012 may remain untreated. If treatment of the formationgenerates thermal fractures in the non-leached/non-fractured portion8032 that propagate towards and/or past freeze wells 8012, the fracturesmay remain substantially horizontally oriented. Horizontally orientedfractures will not intersect the leached/fractured portion 8030 to allowformation water to enter into treatment area 8000.

[1872] Various types of refrigeration systems may be used to form a lowtemperature zone. Determination of an appropriate refrigeration systemmay be based on many factors, including, but not limited to: type offreeze well; a distance between adjacent freeze wells; refrigerant; timeframe in which to form a low temperature zone; depth of the lowtemperature zone; temperature differential to which the refrigerant willbe subjected; chemical and physical properties of the refrigerant;environmental concerns related to potential refrigerant releases, leaks,or spills; economics; formation water flow in the formation; compositionand properties of formation water; and various properties of theformation such as thermal conductivity, thermal diffusivity, and heatcapacity.

[1873] Several different types of freeze wells may be used to form a lowtemperature zone. The type of freeze well used may depend on the type ofrefrigeration system used to form a low temperature zone. The type ofrefrigeration system may be, but is not limited to, a batch operatedrefrigeration system, a circulated fluid refrigeration system, arefrigeration system that utilizes a vaporization cycle, a refrigerationsystem that utilizes an adsorption-desorption refrigeration cycle, or arefrigeration system that uses an absorption-desorption refrigerationcycle. Different types of refrigeration systems may be used at differenttimes during formation and/or maintenance of a low temperature zone. Insome embodiments, freeze wells may include casings. In some embodiments,freeze wells may include perforated casings or casings with other typesof openings. In some embodiments, a portion of a freeze well may be anopen wellbore.

[1874] A batch operated refrigeration system may utilize a plurality offreeze wells. A refrigerant is placed in the freeze wells. Heattransfers from the formation to the freeze wells. The refrigerant may bereplenished or replaced to maintain the freeze wells at desiredtemperatures.

[1875]FIG. 319 depicts an embodiment of batch operated freeze well 8012.Freeze well 8012 may include casing 8034, inlet conduit 8036, ventconduit 8038, and packing 8040. Packing 8040 may be formed near a top ofwhere a low temperature zone is to be formed in a formation. In someembodiments, packing is not utilized. Inlet conduit 8036 and/or ventconduit 8038 may extend through packing 8040. Refrigerant 8041 may beinserted into freeze well 8012 through inlet conduit 8036. Inlet conduit8036 may be insulated, or formed of an insulating material, to inhibitheat transfer to refrigerant 8041 as the refrigerant is transportedthrough the inlet conduit. In an embodiment, inlet conduit 8036 isformed of high density polyethylene. Vapor generated by heat transferbetween the formation and refrigerant 8041 may exit freeze well 8012through vent conduit 8038. In some embodiments, a vent conduit may notbe needed.

[1876] In some freeze well embodiments, a low temperature zone may beformed by batch operated freeze wells that do not include sealedcasings. Portions of freeze wells may be open wellbores, and/or portionsof the wellbores may include casings that have perforations or othertypes of openings. FIG. 320 depicts an embodiment of freeze well 8012that includes an open wellbore portion. To use freeze wells that includeopen wellbore portions and/or perforations or other types of openings,water may be introduced into the freeze wells to fill fractures and/orpore space within the formation adjacent to the wellbore. A pump may beused to remove excess water from the wellbore. In some embodiments,addition of water into the wellbore may not be necessary. Cryogenicrefrigerant 8041, such as liquid nitrogen, may be introduced into thewellbores to freeze material in the formation adjacent to the wellboresand seal any fractures or pore spaces of the formation that are adjacentto the freeze wells. Cryogenic refrigerant 8041 may be periodicallyreplenished so that a frozen barrier is formed and maintained.Alternately, a less cold, less expensive fluid, (such as a dry ice andlow freezing point liquid bath) may be substituted for the cryogenicrefrigerant after evaporation or removal of the cryogenic refrigerantfrom the wellbores. The less cold fluid may be used to form and/ormaintain the frozen barrier.

[1877] A need to replenish refrigerant may make the use of batchoperated freeze wells economical only for forming a low temperature zonearound a relatively small treatment area. The need to replenishrefrigerant may allow for economical operation of batch operated freezewells only for relatively short periods of time. Batch operated freezewells may advantageously be able to form a frozen barrier in a shortperiod of time, especially if a close freeze well spacing and acryogenic fluid is used. Batch operated freeze wells may be able to forma frozen barrier even when there is a large fluid flow rate adjacent tothe freeze wells. Batch operated freeze wells that use liquid nitrogenmay be able to form a frozen barrier when formation fluid flows at arate of up to about 20 m/day.

[1878] A circulated refrigeration system may utilize a plurality offreeze wells. A refrigerant may be circulated through the freeze wellsand through a refrigeration unit. The refrigeration unit may cool therefrigerant to an initial refrigerant temperature. The freeze wells maybe coupled together in series, parallel, or series and parallelcombinations. The circulated refrigeration system may be a high volumesystem. When the system is initially started, the temperature differencebetween refrigerant entering a refrigeration unit and leaving arefrigeration unit may be relatively large (e.g., from about 10° C. toabout 30° C.) and may quickly diminish. After formation of a frozenbarrier, the temperature difference may be 1° C. or less. It may bedesirable for the temperature of the circulated refrigerant to be verylow after the refrigerant passes through a refrigeration unit so thatthe refrigerant will be able to form a thick low temperature zoneadjacent to the freeze wells. An initial working temperature of therefrigerant may be −25° C., −40° C., −50° C., or lower.

[1879]FIG. 321 depicts an embodiment of a circulated refrigerant type ofrefrigeration system that may be used to form low temperature zone 8017around treatment area 8000. The refrigeration system may includerefrigeration units 8042, cold side conduit 8044, warm side conduit8046, and freeze wells 8012. Cold side conduits 8044 and warm sideconduits 8046 (as shown in FIG. 318) may be made of insulated polymerpiping such as HDPE (high-density polyethylene). Cold side conduits 8044and warm side conduits 8046 may couple refrigeration units 8042 tofreeze wells 8012 in series, parallel, or series and parallelarrangements. The type of piping arrangement used to connect freezewells 8012 to refrigeration units 8042 may depend on the type ofrefrigeration system, the number of refrigeration units, and the heatload required to be removed from the formation by the refrigerant.

[1880] In some embodiments, freeze wells 8012 may be connected torefrigeration conduits 8044, 8046 in a parallel configuration asdepicted in FIG. 321. Cold side conduit 8044 may transport refrigerantfrom a first storage tank of refrigeration unit 8042 to freeze wells8012. The refrigerant may travel through freeze wells 8012 to warm sideconduit 8046. Warm side conduit 8046 may transport the refrigerant to asecond storage tank of refrigeration unit 8042. Parallel configurationsfor refrigeration systems may be utilized when a low temperature zoneextends for a long length (e.g., 50 m or longer). Several refrigerationsystems may be needed to form a perimeter barrier around a treatmentarea.

[1881] In some embodiments, freeze wells may be connected torefrigeration conduits in parallel and series configurations. Two ormore freeze wells may be coupled together in a series piping arrangementto form a group. Each group may be coupled in a parallel pipingarrangement to the cold side conduit and the warm side conduit.

[1882] A circulated fluid refrigeration system may utilize a liquidrefrigerant that is circulated through freeze wells. A liquidcirculation system utilizes heat transfer between a circulated liquidand the formation without a significant portion of the refrigerantundergoing a phase change. The liquid may be any type of heat transferfluid able to function at cold temperatures. Some of the desiredproperties for a liquid refrigerant are: a low working temperature, lowviscosity, high specific heat capacity, high thermal conductivity, lowcorrosiveness, and low toxicity. A low working temperature of therefrigerant allows for formation of a large low temperature zone arounda freeze well. A low working temperature of the liquid should be about−20° C. or lower. Fluids having low working temperatures at or below−20° C. may include certain salt solutions (e.g., solutions containingcalcium chloride or lithium chloride). Other salt solutions may includesalts of certain organic acids (e.g., potassium formate, potassiumacetate, potassium citrate, ammonium formate, ammonium acetate, ammoniumcitrate, sodium citrate, sodium formate, sodium acetate). One liquidthat may be used as a refrigerant below −50° C. is Freezium®, availablefrom Kemira Chemicals (Helsinki, Finland). Another liquid refrigerant isa solution of ammonia and water with a weight percent of ammonia betweenabout 20% and about 40%.

[1883] A refrigerant that is capable of being chilled below a freezingtemperature of formation water may be used to form a low temperaturezone. The following equation (the Sanger equation) may be used to modelthe time t₁ needed to form a frozen barrier of radius R around a freezewell having a surface temperature of T_(s): $\begin{matrix}{{t_{1} = {\frac{R^{2}L_{1}}{4\quad k_{f}v_{s}}\left( {{2\ln \quad \frac{R}{r_{0}}} - 1 + \frac{c_{vf}v_{s}}{L_{1}}} \right)}}\text{in~~which:}{L_{1} = {L\quad \frac{a_{r}^{2} - 1}{2\quad \ln \quad a_{r}}c_{vu}v_{o}}}{a_{r} = {\frac{R_{A}}{R}.}}} & (42)\end{matrix}$

[1884] In these equations, k_(f) is the thermal conductivity of thefrozen material; c_(vf) and c_(vu) are the volumetric heat capacity ofthe frozen and unfrozen material, respectively; r_(o) is the radius ofthe freeze well; v_(s) is the temperature difference between the freezewell surface temperature T_(s) and the freezing point of water T_(o);v_(o) is the temperature difference between the ambient groundtemperature T_(g) and the freezing point of water T_(o); L is thevolumetric latent heat of freezing of the formation; R is the radius atthe frozen-unfrozen interface; and R_(A) is a radius at which there isno influence from the refrigeration pipe. The temperature of therefrigerant is an adjustable variable that may significantly affect thespacing between refrigeration pipes.

[1885]FIG. 322 shows simulation results as a plot of time to reduce atemperature midway between two freeze wells to 0° C. versus well spacingusing refrigerant at an initial temperature of −50° C. and usingrefrigerant at an initial temperature of −25° C. The formation beingcooled in the simulation was 83.3 liters of liquid oil/metric ton oilshale. The results for the −50° C. temperature refrigerant are denotedby reference numeral 8048. The results for the −25° C. temperaturerefrigerant are denoted by reference numeral 8050. This figure showsthat reducing refrigerant temperature will reduce the time needed toform an interconnected low temperature zone sufficiently cold to freezeformation water. For example, reducing the initial refrigeranttemperature from −25° C. to −50° C. may halve the time needed to form aninterconnected low temperature zone for a given spacing between freezewells.

[1886] In certain circumstances (e.g., where hydrocarbon containingportions of a formation are deeper than about 300 m), it may bedesirable to minimize the number of freeze wells (i.e., increase freezewell spacing) to improve project economics. Using a refrigerant that cango to low temperatures allows for the use of a large freeze wellspacing.

[1887] EQN. 42 implies that a large low temperature zone may be formedby using a refrigerant having an initial temperature that is very low.To form a low temperature zone for in situ conversion processes forformations, the use of a refrigerant having an initial cold temperatureof about −50° C. or lower may be desirable. Refrigerants having initialtemperatures warmer than about −50° C. may also be used, but suchrefrigerants may require longer times for the low temperature zonesproduced by individual freeze wells to connect. In addition, suchrefrigerants may require the use of closer freeze well spacings and/ormore freeze wells.

[1888] A refrigeration unit may be used to reduce the temperature of arefrigerant liquid to a low working temperature. In some embodiments,the refrigeration unit may utilize an ammonia vaporization cycle.Refrigeration units are available from Cool Man Inc. (Milwaukee, Wis.),Gartner Refrigeration & Manufacturing (Minneapolis, Minn.), and othersuppliers. In some embodiments, a cascading refrigeration system may beutilized with a first stage of ammonia and a second stage of carbondioxide. The circulating refrigerant through the freeze wells may be 30weight % ammonia in water (aqua ammonia).

[1889] In some embodiments, refrigeration units for chilling refrigerantmay utilize an absorption-desorption cycle. An absorption refrigerationunit may produce temperatures down to about −60° C. using thermalenergy. Thermal energy sources used in the desorption unit of theabsorption refrigeration unit may include, but are not limited to, hotwater, steam, formation fluid, and/or exhaust gas. In some embodiments,ammonia is used as the refrigerant and water as the absorbent in theabsorption refrigeration unit. Absorption refrigeration units areavailable from Stork Thermeq B. V. (Hengelo, The Netherlands).

[1890] A vaporization cycle refrigeration system may be used to formand/or maintain a low temperature zone. A liquid refrigerant may beintroduced into a plurality of wells. The refrigerant may absorb heatfrom the formation and vaporize. The vaporized refrigerant may becirculated to a refrigeration unit that compresses the refrigerant to aliquid and reintroduces the refrigerant into the freeze wells. Therefrigerant may be, but is not limited to, ammonia, carbon dioxide, or alow molecular weight hydrocarbon (e.g., propane). After vaporization,the fluid may be recompressed to a liquid in a refrigeration unit orrefrigeration units and circulated back into the freeze wells. The useof a circulated refrigerant system may allow economical formation and/ormaintenance of a long low temperature zone that surrounds a largetreatment area. The use of a vaporization cycle refrigeration system mayrequire a high pressure piping system.

[1891]FIG. 323 depicts an embodiment of freeze well 8012. Freeze well8012 may include casing 8034, inlet conduit 8036, spacers 8052, andwellcap 8051. Spacers 8052 may position inlet conduit 8036 within casing8034 so that an annular space is formed between the casing and theconduit. Spacers 8052 may promote turbulent flow of refrigerant in theannular space between inlet conduit 8036 and casing 8034, but thespacers may also cause a significant fluid pressure drop. Turbulentfluid flow in the annular space may be promoted by roughening the innersurface of casing 8034, by roughening the outer surface of inlet conduit8036, and/or by having a small cross-sectional area annular space thatallows for high refrigerant velocity in the annular space. In someembodiments, spacers are not used.

[1892] Refrigerant may flow through cold conduit 8044 from arefrigeration unit to inlet conduit 8036 of freeze well 8012. Therefrigerant may flow through an annular space between inlet conduit 8036and casing 8034 to warm side conduit 8046. Heat may transfer from theformation to casing 8034 and from the casing to the refrigerant in theannular space. Inlet conduit 8036 may be insulated to inhibit heattransfer to the refrigerant during passage of the refrigerant intofreeze well 8012. In an embodiment, inlet conduit 8036 is a high densitypolyethylene tube. In other embodiments, inlet conduit 8036 is aninsulated metal tube.

[1893]FIG. 324 depicts an embodiment of circulated refrigerant freezewell 8012. Refrigerant may flow through U-shaped conduit 8054 that issuspended or packed in casing 8034. Suspending conduit 8054 in casing8034 may advantageously provide thermal contraction and expansion roomfor the conduit. In some embodiments, spacers may be positioned atselected locations along the length of the conduit to inhibit conduit8054 from contacting casing 8034. Typically, preventing conduit 8054from contacting casing 8034 is not needed, so spacers are not used.Casing 8034 may be filled with a low freezing point heat transfer fluidto enhance thermal contact and promote heat transfer between theformation, casing, and conduit 8054. In some embodiments, water or otherfluid that will solidify when refrigerant flows through conduit 8054 maybe placed in casing 8034. The solid formed in casing 8034 may enhanceheat transfer between the formation, casing, and refrigerant withinconduit 8054. Portions of conduit 8054 adjacent to the formation thatare not to be cooled may be formed of an insulating material (e.g., highdensity polyethylene) and/or the conduit portions may be insulated.Portions of conduit 8054 adjacent to the formation that are to be cooledmay be formed of a thermally conductive metal (e.g., copper or a copperalloy) to enhance heat transfer between the formation and refrigerantwithin the conduit portion.

[1894] In some freeze well embodiments, U-shaped conduits may besuspended or packed in open wellbores or in perforated casings insteadof in sealed casings. FIG. 325 depicts an embodiment of freeze well 8012having an open wellbore portion. Open wellbores and/or perforatedcasings may be used when water or other fluid is to be introduced intothe formation from the freeze wells. Water may be introduced into theformation to promote formation of a frozen barrier. Water may beintroduced into the formation through freeze wells during cleanupprocedures after completion of an in situ conversion process (e.g., thefreeze wells may be thawed and perforated for introduction of water). Insome embodiments, open wellbores and/or perforated casings may be usedwhen the freeze wells will later be converted to heat sources,production wells, and/or injection wells.

[1895] As depicted in FIG. 325, outlet leg 8056 of U-shaped conduit 8054may be wrapped around inlet leg 8058 adjacent to a portion of theformation that is to be cooled. Wrapping outlet leg 8056 around inletleg 8058 may significantly increase the heat transfer surface area ofconduit 8054. Inlet leg and outlet leg adjacent to portions of theformation that are not to be cooled may be insulated and/or made of aninsulating material. Conduits with an outlet leg wrapped around an inletleg are available from Packless Hose, Inc. (Waco, Tex.).

[1896] A time needed to form a low temperature zone may be dependent ona number of factors and variables. Such factors and variables mayinclude, but are not limited to, freeze well spacing, refrigeranttemperature, length of the low temperature zone, fluid flow rate intothe treatment area, salinity of the fluid flowing into the treatmentarea, and the refrigeration system type, or refrigerant used to form thebarrier. The time needed to form the low temperature zone may range fromabout two days to more than a year depending on the extent and spacingof the freeze wells. In some embodiments, a time needed to form a lowtemperature zone may be about 6 to 8 months.

[1897] Spacing between adjacent freeze wells may be a function of anumber of different factors. The factors may include, but are notlimited to, physical properties of formation material, type ofrefrigeration system, type of refrigerant, flow rate of material into orout of a treatment area defined by the freeze wells, time for formingthe low temperature zone, and economic considerations. Consolidated orpartially consolidated formation material may allow for a largeseparation distance between freeze wells. A separation distance betweenfreeze wells in consolidated or partially consolidated formationmaterial may be from about 3 m to 10 m or larger. In an embodiment, thespacing between adjacent freeze wells is about 5 m. Spacing betweenfreeze wells in unconsolidated or substantially unconsolidated formationmaterial may need to be smaller than spacing in consolidated formationmaterial. A separation distance between freeze wells in unconsolidatedmaterial may be 1 m or more.

[1898] Numerical simulations may be used to determine spacing for freezewells based on known physical properties of the formation. A generalpurpose simulator, such as the Steam, Thermal and Advanced ProcessesReservoir Simulator (STARS), may be used for numerical simulation work.Also, a simulator for freeze wells, such as TEMP W available fromGeoslope (Calgary, Alberta), may be used for numerical simulations. Thenumerical simulations may include the effect of heat sources operatingwithin a treatment area defined by the freeze wells.

[1899] A time needed to form a frozen barrier may be determined bycompleting a thermal analysis using a finite element model. FIG. 326depicts results of a simulation using TEMP W for 83.3 liters of liquidoil/metric ton of oil shale presented as temperature versus time for aformation cooled with a refrigerant that has an initial workingtemperature of −50° C. Curve 8060 depicts a representation of atemperature of an outer wall of a freeze well casing. Curve 8062 depictsa temperature midway between two freeze wells that are separated byabout 7.6 m. Curve 8064 depicts temperature midway between two freezewells that are separated by about 6.1 m. Curve 8066 depicts temperaturemidway between two freeze wells that are separated by about 4.6 m.

[1900]FIG. 326 illustrates that closer freeze well spacing decreases anamount of time required to form an interconnected low temperature zonecapable of freezing formation water. The freeze well casing temperaturedecreased from about 14° C. to less than −40° C. in less than 200 days.In the same time frame, a temperature at a midpoint between two freezewells with a 4.6 m spacing decreased from about 14° C. to −5° C. As thespacing between the freeze wells increased, the time needed to reduce atemperature at a midpoint between two freeze wells also increased. Theplot indicates that shorter distances between adjacent freeze wells maydecrease the time necessary to form an interconnected low temperaturezone. The freeze wells in the simulation are similar to the freeze wellsdepicted in FIG. 323.

[1901] The use of a specific type of refrigerant may be made based on anumber of different factors. Such factors may include, but are notlimited to, the type of refrigeration system employed, the chemicalproperties of the refrigerant, and the physical properties of therefrigerant.

[1902] Refrigerants may have different equipment requirements. Forexample, cryogenic refrigerants (e.g., liquid nitrogen) may inducegreater temperature differentials than a brine solution. A required flowrate for a circulated cryogenic refrigerant system may be substantiallylower than a required flow rate for a brine solution refrigerant toachieve a desired temperature in a formation. A required volume ofcryogenic refrigerant for a batch refrigeration system may be large. Theuse of a cryogenic refrigerant may result in significant equipmentsavings, but the cost of reducing refrigerant to cryogenic temperaturesmay make the use of a cryogenic refrigeration system uneconomical.

[1903] Fluid flow into a treatment area may inhibit formation of afrozen barrier. Formations having high permeability may have high fluidflow rates that inhibit formation of a frozen barrier. Fluid flow ratemay limit a residence time of a fluid in a low temperature zone around afreeze well. If fluid is flowing rapidly adjacent to a freeze well, aresidence time of the fluid proximate the freeze well may beinsufficient to allow the fluid to freeze in a cylindrical patternaround the freeze well. Fluid flow rate may influence the shape of abarrier formed around freeze wells. A high flow rate may result inirregular low temperature zones around freeze wells. FIG. 327 depictsshapes of low temperature zones 8017 around freeze wells 8012 whenformation water flows by the freeze wells at a rate that allows forformation of frozen perimeter barrier 8002. Direction of formation waterflow is indicated by arrows 8073. As time passes, the frozen barrier mayexpand outwards from the freeze wells. If the formation water flow rateis high enough, the fluid may inhibit overlap of low temperature zones8017 between adjacent wells, as depicted in FIG. 328. In such asituation, formation fluid would continue to flow into a treatment areaand formation of a frozen barrier would be inhibited. To alleviate theproblem of non-closure of the low temperature zone, additional freezewells may be installed between the existing freeze wells, dewateringwells may be used to reduce formation fluid flow rate by the freezewells to allow for formation of an interconnected low temperature zone,or other techniques may be used to reduce formation fluid flow to a ratethat will allow low temperature zones from adjacent wells tointerconnect so that a frozen barrier forms.

[1904] In some embodiments, fluid flow into a treatment area may beinhibited to allow formation of a frozen barrier by freeze wells. In anembodiment, dewatering wells may be placed in the formation to inhibitfluid flow past freeze wells during formation of a frozen barrier. Thedewatering wells may be placed far enough away from the freeze wells sothat the dewatering wells do not create a flow rate past the freezewells that inhibits formation of a frozen barrier. In some embodiments,injection wells may be used to inject fluid into the formation so thatfluid flow by the freeze wells is reduced to a level that will allow forformation of interconnected frozen barriers between adjacent freezewells.

[1905] In an embodiment, freeze wells may be positioned between an innerrow and an outer row of dewatering wells. The inner row of dewateringwells and the outer row of dewatering wells may be operated to have aminimal pressure differential so that fluid flow between the inner rowof dewatering wells and the outer row of dewatering wells is minimized.The dewatering wells may remove formation water between the outerdewatering row and the inner dewatering row. The freeze wells may beinitialized after removal of formation water by the dewatering wells.The freeze wells may cool the formation between the inner row and theouter row to form a low temperature zone. The power supplied to thedewatering wells may be reduced stepwise after the freeze wells form aninterconnected low temperature zone that is able to solidify formationwater. Reduction of power to the dewatering wells may allow some waterto enter the low temperature zone. The water may freeze to form a frozenbarrier. Operation of the dewatering wells may be ended when the frozenbarrier is fully formed.

[1906] In some formations, a combination batch refrigeration system andcirculated fluid refrigeration system may be used to form a frozenbarrier when fluid flow into the formation is too high to allowformation of the frozen barrier using only the circulated refrigerationsystem. Batch freeze wells may be placed in the formation and operatedwith cryogenic refrigerant to form an initial frozen barrier thatinhibits or stops fluid flow towards freeze wells of a circulated fluidrefrigeration system. Circulation freeze wells may be placed on a sideof the batch freeze wells towards a treatment area. The batch freezewells may be operated to form a perimeter barrier that stops or reducesfluid flow to the circulation freeze wells. The circulation freeze wellsmay be operated to form a primary perimeter barrier. After formation ofthe primary frozen barrier, use of the batch freeze wells may bediscontinued. Alternately, some or all of the batch operated freezewells may be converted to circulation freeze wells that maintain and/orexpand the initial barrier formed by the batch freeze wells. Convertingsome or all of the batch freeze wells to circulation freeze wells mayallow a thick frozen barrier to be formed and maintained around atreatment area. In some embodiments, a combination of dewatering wellsand batch operated freeze wells may be used to reduce fluid flow pastcirculation freeze wells so that the circulation freeze wells form afrozen barrier.

[1907] Open wellbore freeze wells may be utilized in some formationsthat have very low permeability. Freeze well wellbores may be formed insuch formations. A frozen barrier may initially be formed using a verycold fluid, such as liquid nitrogen, that is placed in casings of thefreeze wells. After the very cold fluid forms an interconnected frozenbarrier around the treatment area, the very cold cryogenic fluid may bereplaced with a circulated refrigerant that will maintain the frozenbarrier during in situ processing of the formation. For example, liquidnitrogen at a temperature of about −196° C. may be used to form aninterconnected frozen barrier around a treatment area by placing theliquid nitrogen within the freeze wells and replenishing the liquidnitrogen when necessary. The liquid nitrogen may be placed in an annularspace between an inlet line and a casing in each freeze well. After theliquid nitrogen forms an interconnected frozen barrier between adjacentfreeze wells, the liquid nitrogen may be removed from the freeze wells.A fluid, such as a low freezing point alcohol, may be circulated intoand out of the freeze wells to raise the temperature adjacent to thefreeze wells. When the temperature of the well casing is sufficientlyhigh to inhibit refrigerant, such as a brine solution, from solidifyingin the freeze wells, the fluid may be replaced with the refrigerant. Therefrigerant may be used to maintain the frozen barrier.

[1908]FIG. 307 depicts freeze wells 8012 installed around treatmentareas 8000. ICP wells 8004 may be installed in treatment areas 8000prior to, simultaneously with, or after insertion of freeze wells 8012.In some embodiments, wellbores for ICP wells 8004 and/or freeze wells8012 may be drilled into a formation. In other embodiments, wellboresmay be formed when the wells are vibrationally inserted and/or driveninto the formation. In some embodiments, well casings are formed of pipesegments. Connections between lengths of pipe may be self-sealingtapered threaded connections, and/or welded joints. In otherembodiments, well casings may be inserted using coiled tubinginstallation. Integrity of coiled tubing may be tested beforeinstallation by hydrotesting at pressure.

[1909] Coiled tubing installation may reduce a number of welded and/orthreaded connections in a length of casing. Welds and/or threadedconnections in coiled tubing may be pre-tested for integrity (e.g., byhydraulic pressure testing). Coiled tubing may be installed more easilyand faster than installation of pipe segments joined together bythreaded and/or welded connections.

[1910] Embodiments of heat sources, production wells, and/or freezewells may be installed in a formation using coiled tubing installation.Some embodiments of heat sources, production wells, and freeze wellsinclude an element placed within an outer casing. For example, aconductor-in-conduit heater may include an outer casing with a conduitdisposed in the casing. A production well may include a heater elementor heater elements disposed within a casing. A freeze well may include arefrigerant inlet conduit disposed within a casing, or a U-shapedconduit disposed in a casing. Spacers may be spaced along a length of anelement, or elements, positioned within a casing to inhibit the element,or elements, from contacting the casing walls.

[1911] In some embodiments of heat sources, production wells, and freezewells, casings may be installed using coiled tube installation. Elementsmay be placed within the casing after the casing is placed in theformation for heat sources or wells that include elements within thecasings. In some embodiments, sections of casings may be threaded and/orwelded and inserted into a wellbore using a drilling rig. In someembodiments, elements may be placed within the casing before the casingis wound onto a reel. The elements within a casing are installed in aformation when the casing is installed in the formation. For example, acoiled tubing reel for forming a freeze well such as the freeze welldepicted in FIG. 323 may include 8.9 cm (3.5 in.) outer diameter carbonsteel coiled tubing with 5.1 cm (2 in.) outer diameter high densitypolyethylene tubing positioned inside the carbon steel tubing. Duringinstallation, a portion of the polyethylene tubing may be cut so thatthe polyethylene tubing will be recessed within the steel casing. Awellcap may be threaded and/or welded to the steel tubing to seal theend of the tubing. The coiled tubing may be inserted by a coiled tubingunit into the formation.

[1912] Care may be taken during design and installation of freeze wellcasing strings to allow for thermal contraction of the casing stringwhen refrigerant passes through the casing. Allowance for thermalcontraction may inhibit the development of stress fractures and leaks inthe casing. If a freeze well casing were to leak, leaking refrigerantmay inhibit formation of a frozen barrier or degrade an existing frozenbarrier. Water or other diluent may be used to flush the formation todiffuse released refrigerant if a leak occurs.

[1913] Diameters of freeze well casings installed in a formation may beoversized as compared to a minimum diameter needed to allow forformation of a low temperature zone. For example, if design calculationsindicate that 10.2 cm (4 in.) piping is needed to provide sufficientheat transfer area between the formation and the freeze wells, 15.2 cm(6 in.) piping may be placed in the formation. The oversized casing mayallow a sleeve or other type of seal to be placed into the casing shoulda leak develop in the freeze well casing.

[1914] In some embodiments, flow meters may be used to monitor for leaksof refrigerant within freeze wells. A first flow meter may measure anamount of refrigerant flow into a freeze well or a group of wells. Asecond flow meter may measure an amount of flow out of a freeze well ora group of freeze wells. A significant difference between themeasurements taken by the first flow meter and the second flow meter mayindicate a leak in the freeze well or in a freeze well of the group offreeze wells. A significant difference between the measurements mayresult in the activation of a solenoid valve that inhibits refrigerantflow to the freeze well or group of freeze wells.

[1915] Freeze well placement may vary depending on a number of factors.The factors may include, but are not limited to, predominant directionof fluid flow within the formation; type of refrigeration system used;spacing of freeze wells; and characteristics of the formation such asdepth, length, thickness, and dip. Placement of freeze wells may alsovary across a formation to account for variations in geological strata.In some embodiments, freeze wells may be inserted into hydrocarboncontaining portions of a formation. In some embodiments, freeze wellsmay be placed near hydrocarbon containing portions of a formation. Insome embodiments, some freeze wells may be positioned in hydrocarboncontaining portions while other freeze wells are placed proximate thehydrocarbon containing portions. Placement of heat sources, dewateringwells, and/or production wells may also vary depending on the factorsaffecting freeze well placement.

[1916] ICP wells may be placed a large distance away from freeze wellsused to form a low temperature zone around a treatment area. In someembodiments, ICP wells may be positioned far enough away from freezewells so that a temperature of a portion of formation between the freezewells and the ICP wells is not influenced by the freeze wells or the ICPwells when the freeze wells have formed an interconnected frozen barrierand ICP wells have raised temperatures throughout a treatment area topyrolysis temperatures. In some embodiments, ICP wells may be placed 20m, 30 m, or farther away from freeze wells used to form a lowtemperature zone.

[1917] In some embodiments, ICP wells may be placed in a relativelyclose proximity to freeze wells. During in situ conversion, a hot zoneestablished by heat sources and a cold zone established by freeze wellsmay reach an equilibrium condition where the hot zone and the cold zonedo not expand towards each other. FIG. 329 depicts thermal simulationresults after 1000 days when heat source 8022 at about 650° C. is placedat a center of a ring of freeze wells 8012 that are about 9.1 m awayfrom the heat source and spaced at about 2.4 m intervals. The freezewells are able to maintain frozen barrier 8002 that extends over 1 minwards towards the heat source. On an outer side of the freeze wells,the freeze barrier is much thicker, and the freeze wells influenceportions (e.g., low temperature zone 8017) of the formation up to about15 m away from the freeze wells.

[1918] Thermal diffusivities and other properties of both saturatedfrozen formation material and hot, dry formation material may allowoperation of heat sources close to freeze wells. These properties mayinhibit the heat provided by the heat sources from breaking through afrozen barrier established by the freeze wells. Frozen saturatedformation material may have a significantly higher thermal diffusivitythan hot, dry formation material. The difference in the thermaldiffusivity of hot, dry formation material and cold, saturated formationmaterial predicts that a cold zone will propagate faster than a hotzone. Fast propagation of a cold zone established and maintained byfreeze wells may inhibit a hot zone formed by heat sources from meltingthrough the cold zone during thermal treatment of a treatment area.

[1919] In some embodiments, a heat source may be placed relatively closeto a frozen barrier formed and maintained by freeze wells without theheat source being able to break through the frozen barrier. Although aheat source may be placed close to a frozen barrier, heat sources aretypically placed 5 m or farther away from a frozen barrier formed andmaintained by freeze wells. In an embodiment, heat sources are placedabout 30 m away from freeze wells. Since the heat sources may be placedrelatively close to the frozen barrier, a relatively large section of aformation may be treated without an excessive number of freeze wells. Anumber of freeze wells needed to surround an area increases at asignificantly lower rate than the number of ICP wells needed tothermally treat the surrounded area as the size of the surrounded areaincreases. This is because the surface-to-volume ratio decreases withthe radius of a treated volume.

[1920] Measurable properties and/or testing procedures may indicateformation of a frozen barrier. For example, if dewatering is takingplace on an inner side of freeze wells, the amount of water removed fromthe formation through dewatering wells may significantly decrease as afrozen barrier forms and blocks recharge of water into a treatment area.

[1921] A treatment area may be saturated with formation water. When afrozen perimeter barrier is formed around the treatment area, waterrecharge and removal from the treatment area is stopped. The frozenperimeter barrier may continue to expand. Expansion of the perimeterbarrier may cause the hydrostatic head (i.e., piezometric head) in thetreatment area to rise as compared to the hydrostatic head of formationoutside of the frozen barrier. The hydrostatic head in the barrier mayrise because the water in the formation is confined in an increasinglysmaller volume as the frozen barrier expands inwards. The hydrostaticchange may be relatively small, but still measurable. Piezometers placedinside and outside of a ring of freeze wells may be used to determinewhen a frozen barrier is formed based on hydrostatic head measurements.

[1922] In addition, transient pressure testing (e.g., drawdown tests orinjection tests) in the treatment area may indicate formation of afrozen barrier. Such transient pressure tests may also indicate thepermeability at the barrier. Pressure testing is described in PressureBuildup and Flow Tests in Wells by C. S. Matthews & D. G. Russell (SPEMonograph, 1967).

[1923] A transient fluid pulse test may be used to determine or confirmformation of a perimeter barrier. A treatment area may be saturated withformation water after formation of a perimeter barrier. A pulse may beinstigated inside a treatment area surrounded by the perimeter barrier.The pulse may be a pressure pulse that is produced by pumping fluid(e.g., water) into or out of a wellbore. In some embodiments, thepressure pulse may be applied in incremental steps, and responses may bemonitored after each step. After the pressure pulse is applied, thetransient response to the pulse may be measured by, for example,measuring pressures at monitor wells and/or in the well in which thepressure pulse was applied. Monitoring wells used to detect pressurepulses may be located outside and/or inside of the treatment area.

[1924] In some embodiments, a pressure pulse may be applied by drawing avacuum on the formation through a wellbore. If a frozen barrier isformed, a portion of the pulse will be reflected by the frozen barrierback towards the source of the pulse. Sensors may be used to measureresponse to the pulse. In some embodiments, a pulse or pulses areinstigated before freeze wells are initialized. Response to the pulsesis measured to provide a base line for future responses. After formationof a perimeter barrier, a pressure pulse initiated inside of theperimeter barrier should not be detected by monitor wells outside of theperimeter barrier. Reflections of the pressure pulse measured within thetreatment area may be analyzed to provide information on theestablishment, thickness, depth, and other characteristics of the frozenbarrier.

[1925] In certain embodiments, hydrostatic pressures will tend to changedue to natural forces (e.g., tides, water recharge, etc.). A sensitivepiezometer (e.g., a quartz crystal sensor) may be able to accuratelymonitor natural hydrostatic pressure changes. Fluctuations in naturalhydrostatic pressure changes may indicate formation of a frozen barrieraround a treatment area. For example, if areas surrounding the treatmentarea undergo natural hydrostatic pressure changes but the area enclosedby the frozen barrier does not, this is an indication of formation ofthe frozen barrier.

[1926] In some embodiments, a tracer test may be used to determine orconfirm formation of a frozen barrier. A tracer fluid may be injected ona first side of a perimeter barrier. Monitor wells on a second side ofthe perimeter barrier may be operated to detect the tracer fluid. Nodetection of the tracer fluid by the monitor wells may indicate that theperimeter barrier is formed. The tracer fluid may be, but is not limitedto, carbon dioxide, argon, nitrogen, and isotope labeled water orcombinations thereof. A gas tracer test may have limited use insaturated formations because the tracer fluid may not be able to traveleasily from an injection well to a monitor well through a saturatedformation. In a water saturated formation, an isotope labeled water(e.g., deuterated or tritiated water) or a specific ion dissolved inwater (e.g., thiocyanate ion) may be used as a tracer fluid.

[1927] If tests indicate that a frozen perimeter barrier has not beenformed by the freeze wells, the location of incomplete sections of theperimeter barrier may be determined. Pulse tests may indicate thelocation of unformed portions of a perimeter barrier. Tracer tests mayindicate the general direction in which there is an incomplete sectionof perimeter barrier.

[1928] A Temperatures of freeze wells may be monitored to determine thelocation of an incomplete portion of a perimeter barrier around atreatment area. In some freeze well embodiments, such as in theembodiment depicted in FIG. 323 and FIG. 318, freeze well 8012 mayinclude port 8074. Temperature probes, such as resistance temperaturedevices, may be inserted into port 8074. Refrigerant flow to the freezewells may be stopped. Dewatering wells may be operated to draw fluidpast the perimeter barrier. The temperature probes may be moved withinports 8074 to monitor temperature changes along lengths of the freezewells. The temperature may rise quickly adjacent to areas where a frozenbarrier has not formed. After the location of the portion of perimeterbarrier that is unformed is located, refrigerant flow through freezewells adjacent to the area may be increased and/or an additional freezewell may be installed near the area to allow for completion of a frozenbarrier around the treatment area.

[1929] A typical relatively permeable formation treated by a thermaltreatment process may have a thick overburden. Average thickness of anoverburden may be greater than about 20 m, 50 m, or 500 m. Theoverburden may provide a substantially impermeable barrier that inhibitsvapor release to the atmosphere. ICP wells passing into the formationmay include well completions that cement or otherwise seal well casingsfrom surrounding formation material so that formation fluid cannot passto the atmosphere adjacent to the wells.

[1930] In some embodiments of an in situ conversion process, heatsources may be placed in a hydrocarbon containing portion of theformation such that the heat sources do not heat sections of thehydrocarbon containing portion nearest to the ground surface topyrolysis temperatures. The heat sources may heat a section of thehydrocarbon containing portion that is below the untreated section topyrolysis temperatures. The untreated section of hydrocarbon containingmaterial may be considered to be part of the overburden.

[1931] Some formations may have relatively thin overburdens over aportion of the formation. Some formations may have an outcrop thatapproaches or extends to ground surface. In some formations, anoverburden may have fractures or develop fractures during thermalprocessing that connect or approach the ground surface. Some formationsmay have permeable portions that allow formation fluid to escape to theatmosphere when the formation is heated. A ground cover may be providedfor a portion of a formation that will allow, or potentially allow,formation fluid to escape to the atmosphere during thermal processing.

[1932] A ground cover may include several layers. FIG. 330 depicts anembodiment of ground cover 8076. Ground cover 8076 may include fillmaterial 8078 used to level a surface on which the ground cover isplaced, first impermeable layer 8080, insulation 8082, framework 8084,and second impermeable layer 8086. Other embodiments of ground coversmay include a different number of layers. For example, a ground covermay only include a first impermeable layer. In some embodiments, firstimpermeable layer 8080 may be formed of concrete, metal, plastic, clay,or other types of material that inhibit formation fluid from passingfrom the ground to the atmosphere.

[1933] Ground cover 8076 may be sealed to the ground, to ICP wells, tofreeze wells, and to other equipment that passes through the groundcover. Ground cover 8076 may inhibit release of formation fluid to theatmosphere. Ground cover 8076 may also inhibit rain and run-off waterseepage into a treatment area from the ground surface. The choice ofground cover material may be based on temperatures and chemicals towhich ground cover 8076 is subjected. In embodiments in which overburden540 is sufficiently thick so that temperatures at the ground surface arenot influenced, or are only slightly elevated, by heating of theformation, ground cover 8076 may be a polymer sheet. For thinneroverburdens 540, where heating the formation may significantly influencethe temperature at ground surface, ground cover 8076 may be formed ofmetal sheet placed over the treatment area. Ground cover 8076 may beplaced on a graded surface, and wellbores for ICP wells and freeze wellsmay be placed into the formation through the ground cover. Ground cover8076 may be welded or otherwise sealed to well casings and/or otherstructures extending through the ground cover. If needed, insulation8082 may be placed above or below ground cover 8076 to inhibit heat lossto the atmosphere.

[1934] Ground cover 8076 may include framework 8084. In certainembodiments, framework 8084 supports a portion of ground cover 8076. Forexample, framework 8084 may support second impermeable layer 8086, whichmay be a rain cover that extends over a portion or all of the treatmentarea. In other embodiments, framework 8084 supports well casings,walkways, and/or other structures that provide access to wells withinthe treatment area, so that personnel do not have to contact groundcover 8076 when accessing a well or equipment within the treatment area.

[1935] Perforated piping of a piping system may be placed in the groundor adjacent to the ground surface below a ground cover. The perforatedpiping may provide a path for transporting formation fluid passingthrough the formation towards the surface to surface facilities. Inother embodiments, a piping system may be connected to openings thatpass through the ground cover. Blowers or other types of drive systemsmay draw formation fluid adjacent to the ground cover into the piping.Monitor wells may be placed through a ground cover at the groundsurface. If the monitor wells detect formation fluid, the drive systemmay be activated to transport the fluid to a surface facility.

[1936] Ground cover 8076 may be sealed to the ground. In an embodimentof an in situ conversion process, freeze wells 8012 are used to form alow temperature zone around the treatment area. A portion of therefrigerant capacity utilized in freeze wells 8012 may be used to freezea portion of the formation adjacent to the ground surface. Ground cover8076 may include a lip that is pushed into wet ground prior to formationof the low temperature zone. When the low temperature zone is formed,the freeze wells may freeze the ground and the ground cover together.Insulation may be placed over the frozen ground to inhibit heatabsorption from the atmosphere. In other embodiments, a ground cover maybe welded or otherwise sealed to a sheet barrier or a grout wall formedin the formation around the treatment area.

[1937] In some embodiments, an upper layer of a formation (e.g., anoutcrop) that allows, or potentially allows, formation fluid to escapeto the atmosphere during thermal treatment is excavated. The depth ofthe excavation opening created may be about ⅓ m, 1 m, 5 m, 10 m, orgreater. Perforated piping of a piping system may be placed in theexcavation and covered with a permeable layer such as sand and/orgravel. A concrete, clay, or other impermeable layer may be formed as acover over the excavation opening. Alternately, a similar structure maybe built on top of the ground to form an impermeable cover over aportion of a formation. The concrete, clay, or other impermeable layermay function as an artificial overburden.

[1938] A treatment area may be subjected to various processessequentially. Treatment areas may undergo many different processesincluding, but not limited to, initial heating, production ofhydrocarbons, pyrolysis, synthesis gas generation, storage of fluids,sequestration, remediation, use as a filtration unit, solution mining,and/or upgrading of hydrocarbon containing feed streams. Fluids may bestored in a formation as long term storage and/or as temporary storageduring unusual situations such as a power failure or surface facilitiesshutdown. Various factors may be used to determine which processes willbe used in particular treatment areas. Factors determining the use of aformation may include, but are not limited to, formation characteristicssuch as type, size, hydrology, and location; economic viability of aprocess; available market for products produced from the formation;available surface facilities to process fluid removed from theformation; and/or feedstocks for introduction into a formation toproduce desired products.

[1939] For some processes, a low temperature zone may be used to isolatea treatment area. A treatment area surrounded by a low temperature zonemay be used, in certain embodiments, as a storage area for fluidsproduced or needed on site. Fluids may be diverted from other areas ofthe formation in the event of an emergency. Alternatively, fluids may bestored in a treatment area for later use. A low temperature zone mayinhibit flow of stored fluids from a treatment area depending oncharacteristics of the stored fluids. A frozen barrier zone may benecessary to inhibit flow of certain stored fluids from a treatment areaOther processes which may benefit from an isolated treatment zone mayinclude, but are not limited to, synthesis gas generation, upgrading ofhydrocarbon containing feed streams, filtration of feed stocks, and/orsolution mining.

[1940] In some in situ conversion process embodiments, three or moresets of wells may surround a treatment area. FIG. 333 depicts a wellpattern embodiment for an in situ conversion process. Treatment area8000 may include a plurality of heat sources and/or production wells.Treatment area 8000 may be surrounded by a first set of freeze wells8028. The first set of freeze wells 8028 may establish a frozen barrierthat inhibits migration of fluid out of treatment area 8000 during thein situ conversion process.

[1941] The first set of freeze wells 8028 may be surrounded by a set ofmonitor and/or injection wells 8088. Monitor and/or injection wells 8088may be used during the in situ conversion process to monitor temperatureand monitor for the presence of formation fluid (e.g., for water, steam,hydrocarbons, etc.). If hydrocarbons or steam are detected, a breach ofthe frozen barrier established by the first set of freeze wells 8028 maybe indicated. Measures may be taken to determine the location of thebreach in the frozen barrier. After determining the location of thebreach, measures may be taken to stop the breach. In an embodiment, anadditional freeze well or freeze wells may be inserted into theformation between the first set of freeze wells and the set of monitorand/or injection wells 8088 to seal the breach.

[1942] The set of monitor and/or injection wells 8088 may be surroundedby a second set of freeze wells 8029. The second set of freeze wells8029 may form a frozen barrier that inhibits migration of fluid (e.g.,water) from outside the second set of freeze wells into treatment area8000. The second set of freeze wells 8029 may also form a barrier thatinhibits migration of fluid past the second set of freeze wells shouldthe frozen barrier formed by the first set of freeze wells 8028 developa breach. A frozen barrier formed by the second set of freeze wells 8029may stop migration of formation fluid and allow sufficient time for thebreach in the frozen barrier formed by the first set of freeze wells8028 to be fixed. Should a breach form in the frozen barrier formed bythe first set of freeze wells 8028, the frozen barrier formed by thesecond set of freeze wells 8029 may limit the area that formation fluidfrom the treatment area can flow into, and thus the area that needs tobe cleaned after the in situ conversion process is complete.

[1943] If the set of monitor and/or injection wells 8088 detect thepresence of formation water, a breach of the second set of freeze wells8029 may be indicated. Measures may be taken to determine the locationof the breach in the second set of freeze wells 8029. After determiningthe location of the breach, measures may be taken to stop the breach. Inan embodiment, an additional freeze well or freeze wells may be insertedinto the formation between the second set of freeze wells 8029 and theset of monitor and/or injection wells 8088 to seal the breach.

[1944] In many embodiments, monitor and/or injection wells 8088 may notdetect a breach in the frozen barrier formed by the first set of freezewells 8028 during the in situ conversion process. To clean the treatmentarea after completion of the in situ conversion processes, the first setof freeze wells 8028 may be deactivated. Fluid may be introduced throughmonitor and/or injection wells 8088 to raise the temperature of thefrozen barrier and force fluid back towards treatment area 8000. Thefluid forced into treatment area 8000 may be produced from productionwells in the treatment area. If a breach of the frozen barrier formed bythe first set of freeze wells 8028 is detected during the in situconversion process, monitor and/or injection wells 8088 may be used toremediate the area between the first set of freeze wells 8028 and thesecond set of freeze wells 8029 before, or simultaneously with,deactivating the first set of freeze wells. The ability to maintain thefrozen barrier formed by the second set of freeze wells 8029 after insitu conversion of hydrocarbons in treatment area 8000 is complete mayallow for cleansing of the treatment area with little or no possibilityof spreading contaminants beyond the second set of freeze wells 8029.

[1945] The set of monitor and/or injection wells 8088 may be positionedat a distance between the first set of freeze wells 8028 and the secondset of freeze wells 8029 to inhibit the monitor and/or injection wellsfrom becoming frozen. In some embodiments, some or all of the monitorand/or injection wells 8088 may include a heat source or heat sources(e.g., an electric heater, circulated fluid line, etc.) sufficient toinhibit the monitor and/or injection wells from freezing due to the lowtemperature zones created by freeze wells 8028 and freeze wells 8029.

[1946] In some in situ conversion process embodiments, a treatment areamay be treated sequentially. An example of sequentially treating atreatment area with different processes includes installing a pluralityof freeze wells within a formation around a treatment area. Pumpingwells are placed proximate the freeze wells within the treatment area.After a low temperature zone is formed, the pumping wells are engaged toreduce water content in the treatment area. After the pumping wells havereduced the water content, the low temperature zone expands to encompasssome of the pumping wells. Heat is applied to the treatment area usingheat sources. A mixture is produced from the formation. After a majorityof recoverable liquid hydrocarbons is recovered from the formation,synthesis gas generation is initiated. Following synthesis gasgeneration, the treatment area is used as a storage unit for fluidsdiverted from other treatment areas within the formation. The divertedfluids are produced from the treatment area. Before the low temperaturezone is allowed to thaw, the treatment area is remediated. A firstportion of a low temperature zone surrounding the pumping wells isallowed to thaw, exposing an unaltered portion of the formation. Wateris provided to a second portion of a low temperature zone to form afrozen barrier zone. A drive fluid is provided to the treatment areathrough the pumping wells. The drive fluid may move some fluidsremaining in the formation towards wells through which the fluids areproduced. This movement may be the result of steam distillation oforganic compounds, leaching of inorganic compounds into the drive fluidsolution, and/or the force of the drive fluid “pushing” fluids from thepores. Drive fluid is injected into the treatment area until the removeddrive fluid contains concentrations of the remaining fluids that fallbelow acceptable levels. After remediation of a treatment area, carbondioxide is injected into the treatment area for sequestration.

[1947] An alternate example of formation use includes a plurality offreeze wells placed within a formation surrounding a treatment area. Alow temperature zone may be formed around the treatment area. Pumpingwells, heat sources, and production wells are disposed within thetreatment area. Hot water, or water heated in situ by heat sources, maybe introduced into the treatment area to solution mine portions of theformation adjacent to selected wells. After solution mining, thetreatment area may be dewatered. The temperature of the treatment areamay be raised to pyrolysis temperatures, and pyrolysis products may beproduced from the treatment area.

[1948] After pyrolysis, the treatment area may be subjected to asynthesis gas generation process. After synthesis gas generation, thetreatment area may be cleaned. A drive fluid (e.g., water and/or steam)may be introduced into the treatment area to remove (e.g., by steamdistillation) hydrocarbons out of the treatment area. The drive fluidmay be introduced into the treatment area from an outer perimeter of thetreatment area. The drive fluid and any materials in front of, orentrained in, the drive fluid may be produced from production wells inthe interior of the treatment area. After cleaning, the treatment areamay be used as storage for selected products, as an emergency storagefacility, as a carbon dioxide sequestration bed, or for other uses.

[1949] In certain embodiments, adjacent treatment areas may beundergoing different processes concurrently within separate lowtemperature zones. These differing processes may have variedrequirements, for example, temperature and/or required constituents,which may be added to the section. In an embodiment, a low temperaturezone may be sufficient to isolate a first treatment area from a secondtreatment area. An example of differing conditions required by twoprocesses includes a first treatment area undergoing production ofhydrocarbons. In situ generation of synthesis gas may requiretemperatures greater than about 400° C. A second treatment area adjacentto the first may undergo sequestration, a process, which depending onthe component being sequestered, may be optimized at a temperature lessthan about 100° C. Alternatively, providing a barrier to both mass andheat transfer may be necessary in some embodiments. A frozen barrierzone may be utilized to isolate a treatment area from the surroundingformation both thermally and hydraulically. For example, a firsttreatment area undergoing pyrolysis should be isolated both thermallyand hydraulically from a second treatment area in which fluids are beingstored.

[1950] As depicted in FIG. 331 and FIG. 332, dewatering wells 8028 maysurround treatment area 8000. Dewatering wells 8028 that surroundtreatment area 8000 may be used to provide a barrier to fluid flow intothe treatment area or migration of fluid out of the treatment area intosurrounding formation. In an embodiment, a single ring of dewateringwells 8028 surrounds treatment area 8000. In other embodiments, two ormore rings of dewatering wells surround a treatment area. In someembodiments that use multiple rings of dewatering wells 8028, a pressuredifferential between adjacent dewatering well rings may be minimized toinhibit fluid flow between the rings of dewatering wells. Duringprocessing of treatment area 8000, formation water removed by dewateringwells 8028 in outer rings of wells may be substantially the same asformation water in areas of the formation not subjected to in situconversion. Such water may be released with no treatment or minimaltreatment. If removed water needs treatment before being released, thewater may be passed through carbon beds or otherwise treated beforebeing released. Water removed by dewatering wells 8028 in inner rings ofwells may contain some hydrocarbons. Water with significant amounts ofhydrocarbon may be used for synthesis gas generation. In someembodiments, water with significant amounts of hydrocarbons may bepassed through a portion of formation that has been subjected to in situconversion. Remaining carbon within the portion of the formation maypurify the water by adsorbing the hydrocarbons from the water.

[1951] In some embodiments, an outer ring of wells may be used toprovide a fluid to the formation. In some embodiments, the providedfluids may entrain some formation fluids (e.g., vapors). An inner ringof dewatering wells may be used to recover the provided fluids andinhibit the migration of vapors. Recovered fluids may be separated intofluids to be recycled into the formation and formation fluids. Recycledfluids may then be provided to the formation. In some embodiments, apressure gradient within a portion of the formation may increaserecovery of the provided fluids.

[1952] Alternatively, an inner ring of wells may be used for dewateringwhile an outer ring is used to reduce an inflow of groundwater. Incertain embodiments, an inner ring of wells is used to dewater theformation and fluid is pumped into the outer ring to confine vapors tothe inner area.

[1953] Water within treatment area 8000 may be pumped out of thetreatment area prior to or during heating of the formation to pyrolysistemperatures. Removing water prior to or during heating may limit thewater that needs to be vaporized by heat sources so that the heatsources are able to raise formation temperatures to pyrolysistemperatures more efficiently.

[1954] In some embodiments, well spacing between dewatering wells 8028may be arranged in convenient multiples of heater and/or production wellspacing. Some dewatering wells may be converted to heater wells and/orproduction wells during in situ processing of a hydrocarbon formation.Spacing between dewatering wells may depend on a number of factors,including the hydrology of the formation. In some embodiments, spacingbetween dewatering wells may be 2 m, 5 m, 10 m, 20 m, or greater.

[1955] A spacing between dewatering wells and ICP wells, such as heatsources or production wells, may need to be large. The spacing may needto be large so that the dewatering wells and the in situ process wellsare not influenced by each other. In an embodiment, a spacing betweendewatering wells and in situ process wells may need to be 30 m or more.Greater or lesser spacings may be used depending on formationproperties. Also, a spacing between a property line and dewatering wellsmay need to be large so that dewatering does not influence water levelson adjacent property.

[1956] In some embodiments, a perimeter barrier or a portion of aperimeter barrier may be a grout wall, a cement barrier, and/or a sulfurbarrier. For shallow formations, a trench may be formed in the formationwhere the perimeter barrier is to be formed. The trench may be filledwith grout, cement, and/or molten sulfur. The material in the trench maybe allowed to set to form a perimeter barrier or a portion of aperimeter barrier.

[1957] Some grout, cement, or sulfur barriers may be formed in drilledcolumns along a perimeter or portion of a perimeter of a treatment area.A first opening may be formed in the formation. A second opening may beformed in the formation adjacent to the first opening. The secondopening may be formed so that the second opening intersects a portion ofthe first opening along a portion of the formation where a barrier is tobe formed. Additional intersecting openings may be formed so that aninterconnected opening is formed along a desired length of treatmentarea perimeter. After the interconnected openings are formed, a portionof the interconnected opening adjacent to where a barrier is to beformed may be filled with material such as grout, cement, and/or sulfur.The material may be allowed to set to form a barrier.

[1958] In situ treatment of formations may significantly alter formationcharacteristics such as permeability and structural strength. Productionof hydrocarbons from a formation corresponds to removal of hydrocarboncontaining material from the formation. Heat added to the formation may,in some embodiments, fracture the formation. Removal of hydrocarboncontaining material and formation of fractures may influence thestructural integrity of the formation. Selected areas of a treatmentarea may remain untreated to promote structural integrity of theformation, to inhibit subsidence, and/or to inhibit fracturepropagation.

[1959]FIG. 307 depicts a formation separated into a number of treatmentareas 8000. Freeze wells 8012 surrounding treatment areas 8000 may formlow temperature zones around the treatment areas. Formation materialwithin the low temperature zones may be untreated formation materialthat is not exposed to high temperatures during an in situ conversionprocess. Formation water may be frozen in the low temperature zone. Thefrozen water may provide additional structural strength to the formationduring the in situ conversion process. After completion of processingand use of a treatment area, maintenance of the low temperature zone maybe ended and temperature of material within the low temperature zone mayreturn to ambient conditions. The untreated formation material that wasin the low temperature zone may provide structural strength to theformation. The regions of untreated formation may inhibit subsidence ofthe formation.

[1960] In some embodiments of in situ conversion processes, portions ofa formation within a treatment area may not be subjected to temperatureshigh enough to pyrolyze or otherwise significantly change properties ofthe formation. Untreated portions of the formation may stabilize theformation and inhibit subsidence of the formation or overburden. In atreatment area, heat sources are generally placed in patterns withregular spacings between adjacent wells. The spacings may be smallenough to allow superposition of heat between adjacent heat sources. Thesuperposition of heat allows the formation to reach high temperatures. Aregular pattern of heat sources may promote relatively uniform heatingof the treatment area.

[1961] In some embodiments, a disruption of a regular heat sourcepattern may leave sections of formation within a treatment areaunprocessed. A large distance may separate heat sources from sections ofthe formation that are to remain untreated. The distance should allowthe untreated section to be minimally influenced by adjacent heatsources. The distance may be 20 m, 25 m, or greater. In an embodiment ofan in situ treatment process that uses a triangular pattern of heatsources, a well unit (e.g., three heat sources) may be periodicallyomitted from the pattern to leave an untreated portion of formation whenthe formation is subjected to in situ conversion. In other embodiments,more wells than a single unit of wells may be omitted from the pattern(e.g., 4, 5, 6, or more heat source wells may be periodically omittedfrom an equilateral triangle heat source pattern).

[1962] In some embodiments, selected wellbores of a regular heat sourcepattern may be utilized to maintain untreated sections of formationwithin the pattern. A heat transfer fluid may be placed or circulatedwithin casings placed in the selected wellbores. The heat transfer fluidmay maintain adjacent portions of the formation at low enoughtemperatures that allow the portions to be uninfluenced or minimallyinfluenced by heat provided to the formation from adjacent heat sources.The use of selected wellbores to maintain untreated portions of theformation within a treatment area may advantageously eliminate the needto make wellbore pattern alterations during well installation.

[1963] In some embodiments, water may be used as a heat transfer fluidplaced or circulated in selected casings to maintain untreated portionsof a formation. In some embodiments, the heat transfer fluid circulatedin selected casings to maintain untreated portions of formation mayinclude refrigerant utilized to form a low temperature zone around atreatment area. The refrigerant may be circulated in the selected wellsprior to initiation of formation heating so that low temperature zonesare formed around the selected freeze wells. Water in the formation mayfreeze in columns around the selected wells. Heating of the formationmay reduce the size of the columns around the freeze wells, but thefreeze wells should maintain frozen, untreated portions of the formationwithin a heated portion of the formation. The untreated portions mayprovide structural strength to the formation during an in situconversion process and after the in situ conversion process iscompleted.

[1964] Vapor processing facilities that treat production fluid from aformation may include facilities for treating generated hydrogen sulfideand other sulfur containing compounds. The sulfur treatment facilitiesmay utilize a modified Claus process or other process that produceselemental sulfur. Sulfur may be produced in large quantities at an insitu conversion process site.

[1965] Some of the sulfur produced may be liquefied and placed (e.g.,injected) in a spent formation. Stabilizers and other additives may beintroduced into the sulfur to adjust the properties of the sulfur. Forexample, aggregate such as sand, corrosion inhibitors, and/orplasticizers may be added to the molten sulfur. U.S. Pat. No. 4,518,548and U.S. Pat. No. 4,428,700, which are both incorporated by reference asif fully set forth herein, describe sulfur cements.

[1966] A spent formation may be highly porous and highly permeable.Liquefied sulfur may diffuse into pore space within the formation formedby thermally processing hydrocarbons within the formation. The sulfurmay solidify in the formation when the sulfur cools below the meltingtemperature of sulfur (approximately 115° C.). Solidified sulfur mayprovide structural strength to the formation and inhibit subsidence ofthe formation. Solidified sulfur in pore spaces within the formation mayprovide a barrier to fluid flow. If needed at a future time, sulfur maybe produced from the formation by heating the formation and removing thesulfur from the formation.

[1967] In some in situ conversion process embodiments, molten sulfur maybe placed in a formation to form a perimeter barrier around a portion ofthe formation to be subjected to pyrolysis. The perimeter barrier formedby solidified sulfur may provide structural strength to the formation.The perimeter barrier may need to be located a large distance away fromICP wells used during in situ conversion so that heat applied to thetreatment area does not affect the sulfur barrier. In some embodiments,the perimeter barrier may be 20 m, 30 m, or farther away from heatsources of an in situ conversion process system.

[1968] Sulfur barriers may be used in conjunction with a low temperaturezone formed by freeze wells. A low temperature zone, or freeze wall, maybe formed to provide a barrier to fluid flow into or out of a treatmentarea that is subjected to an in situ conversion process. The lowtemperature zone may also provide structural strength to the formationbeing treated. After the treatment area is processed, water or otherfluid may be introduced into the formation to remediate any contaminantswithin the treatment area. Heat may be recovered from the formation byremoving the water or other fluid from the formation and utilizing theheat transferred to the water or fluid for other purposes. Recoveringheat from the formation may reduce the temperature of the formation to atemperature in the vicinity of the melting temperature of sulfuradjacent to the low temperature zone.

[1969] After a temperature of the treatment area is reduced to about thetemperature of molten sulfur, molten sulfur may be introduced into theformation adjacent to the low temperature zone formed by freeze wells,and the molten sulfur may be allowed to diffuse into the formation. Inthe embodiment depicted in FIG. 310, the molten sulfur may be introducedinto the formation through dewatering well 8028. The molten sulfur maysolidify against the frozen barrier formed by freeze well 8012. Aftersolidification of the sulfur, maintenance of the low temperature zonemay be reduced or stopped.

[1970] Solid sulfur within pore spaces may inhibit fluid from migratingthrough the sulfur barrier. For example, carbon dioxide may be adsorbedonto carbon remaining in a formation that has been processed using an insitu conversion process. If water migrates into the formation, the watermay desorb the stored carbon dioxide from the formation. Sulfur injectedinto wells may solidify in pore spaces within the formation to form asulfur cement barrier. The sulfur cement barrier may inhibit watermigration into the formation. The barrier formed by the sulfur mayinhibit removal of stored carbon dioxide from the formation. In someembodiments, sulfur may be introduced throughout a formation instead ofjust as a perimeter barrier. Sulfur may be stored or used to inhibitsubsidence of the formation.

[1971] In some instances, shut-in management of the in situ treatment ofa formation may become necessary. “Shut-in” may be a reduction orcomplete termination of production from a formation undergoing in situtreatment. Adverse events of any kind and/or scheduled maintenance mayrequire shut-in of an in situ treatment process. For example, adverseevents may include malfunctioning or nonfunctioning surface facilities,lack of transport facilities to move products away from the project,breakthrough to the surface or an aquifer, and/or sociopolitical eventsnot directly related to a project.

[1972] Generally, thermal conduction and conversion of hydrocarbonsduring in situ treatment are relatively slow processes. Therefore,shut-in of production may require a relatively long period of time. Forexample, at least some hydrocarbons in the formation may continue to beconverted for months or years after heating from the heat sources isterminated. Consequently, hydrocarbons and other vapors may continue tobe generated, accompanied by a build up of fluid pressure in theformation. Fluid pressure in the formation may exceed the fracturingstrength of the formation and create fractures. As a result,hydrocarbons and other vapors, which may include hydrogen sulfide, maymigrate through the fractures to the surrounding formation, potentiallyreaching groundwater or the surface.

[1973] Shut-in management of an in situ treatment process may include avariety of steps that alleviate problems associated with shut-in of theprocess. In one embodiment, substantially all heating from heat sources,including heater wells and thermal injection, may be terminated.Termination of heating is particularly important if the adverse event orshut down may be of long duration. In addition, substantially allhydrocarbon vapors generated may be produced from the formation. Theproduced hydrocarbon vapors may be flared.

[1974] “Flaring” is oxidation or burning of fluids produced from aformation. It is particularly advantageous for complete combustion ofH₂S to take place. Furthermore, it is desirable to flare methane sincemethane may be a much stronger greenhouse gas than CO₂.

[1975] In certain embodiments, the fluid pressure in the formation maybe maintained below a safe level. The safe fluid pressure level may bebelow an established threshold at which fracturing and breakthroughoccur in the formation. The fluid pressure in the formation may bemonitored by several methods, for example, by passive acousticmonitoring to detect fracturing. “Passive acoustic monitoring” detectsand analyzes microseismic events to determine fracturing in a formation.In an embodiment, a short term response to excessive pressure build upmay be to release formation fluids to other storage (e.g., a spent, coolportion of the formation). Alternatively, formation fluids may beflared.

[1976] In some embodiments, produced formation fluid may be injected andstored in spent formations. A spent formation may be retainedspecifically for receiving produced fluids should a shut-in situationarise. Fluid communication between the spent formation and thesurrounding formation may be limited by a barrier (e.g., a frozenbarrier, a sulfur barrier, etc.). The barrier may inhibit flow of theproduced formation fluid from the spent formation. In an embodiment, thetemperature of the spent formation may be low enough to condense asubstantial portion of condensable fluids. There may be a correspondingdecrease in fluid pressure as formation fluid condenses in the spentformation. The decrease in fluid pressure and volume reduction mayincrease storage capacity of the spent formation. In an embodiment,subsequent heating of the spent formation may allow substantiallycomplete recovery of stored hydrocarbons.

[1977] In certain embodiments, produced formation fluid may be injectedinto relatively high temperature formations. The formation may haveportions with an average temperature high enough to convert asubstantial portion of the injected formation fluid to coke and H₂. H₂may be flared to produce water vapor in some embodiments.

[1978] In an embodiment, produced formation fluid may be injected intopartially produced or depleted formations. The depleted formations mayinclude oil fields, gas fields, or water zones with established seal andtrap integrity. The trapped formation fluid may be recovered at a latertime. In other embodiments, formation fluid may be stored in surfacestorage units.

[1979]FIG. 346 is a flow chart illustrating options for produced fluidsfrom a shut-in formation. Stream 8252 may be produced from shut-information 8250. Stream 8252 may be injected into cooled spent formation8254. Formation 8254 may be reheated at a later time to produce thestored formation fluid, as shown by stream 8255. In addition, stream8252 may be injected into hot formation 8256. A substantial portion ofthe fluids injected into formation 8256 may be converted to coke and H₂.The H₂ may be produced from formation 8256 as stream 8257 and flared.Alternatively, stream 8252 may be injected into depleted oil or gasfield or water zone 8258. Injected formation fluid may be produced at alater time, as stream 8259 illustrates. Furthermore, stream 8252 may bestored in surface storage facilities 8260.

[1980] After completion of an in situ conversion process, formations maybe subjected to additional treatment processes in preparation forabandonment. Processes which may be performed in a formation mayinclude, but are not limited to, recovery of thermal energy from theformation, removal of fluids generated during the in situ conversionprocess through injection of a fluid (water, carbon dioxide, drivefluid), and/or recovery of thermal energy from a frozen barrier orfreeze well.

[1981] Thermal energy may be recovered from formations through theinjection of fluids into the formation. Fluids may be injected and/orremoved through existing heater wells, dewatering wells, and/orproduction wells. In some embodiments, a portion of a formationsubjected to an in situ conversion process may be at an averagetemperature greater than about 300° C. The portion of the formation mayhave a relatively high porosity (e.g., greater than about 20%) and apermeability greater than about 0.3 darcy (e.g., 0.4 darcy, 0.6 darcy,0.9 darcy, 1 darcy, or greater) due to the removal of hydrocarbons fromthe formation. The increased porosity and permeability of the sectionmay reduce the number of wells needed to inject and recover fluid. Forexample, water may be provided to or be removed from the formation usingheater wells that allow, or have been reworked to allow, fluidcommunication between the well and the surrounding formation.

[1982] In some embodiments, fresh water may be injected into theformation. Alternatively, non-potable water, hydrocarbon containingwater, brine, acidic water, alkaline water, or combinations thereof maybe injected into the formation. Compounds in the water may be leftwithin the formation after the water is vaporized by heat within theformation. Some compounds within the water may be absorbed and/oradsorbed onto remaining material within the formation. Introduction ofseveral pore volumes of water may be needed to lower the averagetemperature in the formation below the boiling point of water. In anembodiment, water injection may include geothermal well and othertechnologies developed for utilizing the steam production from hightemperature subterranean formations.

[1983] In certain embodiments, applications of steam recovered from theformation may include direct use for power generation and/or use assensible energy in heat exchange mechanisms. In particular, thermalenergy from recovered steam may be used in project surface facilities(e.g., in heat exchange units, in the desalinization process, or in thedistillation of produced water). The thermal energy from recovered steammay be used for solution mining of nearby mineral resources (e.g.,nahcolite, sulfur, phosphates, etc). Thermal energy from recovered steammay also be used in external industrial applications, such asapplications that require the use of large volumes of steam. Inaddition, thermal energy from recovered steam may be used for municipalpurposes (e.g., heating buildings) and for agricultural purposes (e.g.,heating hothouses or processing products).

[1984] In an in situ conversion process embodiment during a time priorto abandonment, substantially non-reactive gas (e.g., carbon dioxide)may be used as a heat recovery fluid. The substantially non-reactive gasmay be injected into the formation and heat within the formation may betransferred to the substantially non-reactive gas. In some embodiments,the substantially non-reactive gas may recover a substantial portion ofresidual treatment fluids (e.g., low molecular weight hydrocarbons). Thetreatment fluids may be separated from the substantially non-reactivegas at the surface of the formation. For example, some carbon dioxidemay be adsorbed onto the surface of the formation, displacing lowmolecular weight hydrocarbons. In an embodiment, carbon dioxide adsorbedonto formation surfaces during use as a heat recovery fluid may besequestered within the formation. After completion of heat recovery,additional carbon dioxide may be provided to the formation and adsorbedin formation pore spaces for sequestration.

[1985] In an in situ conversion process embodiment, recovery of storedheat in a formation with injected substantially non-reactive gas mayrequire more pore volumes of gas than would have been required had waterbeen used as the heat recovery fluid. This may be due to gases generallyhaving lower sensible heats than liquids. In addition, substantiallynon-reactive gas injection may require initial compression of theinjected gas stream. However, injection and recovery in the gas phasemay be easier than in the liquid phase. In certain embodiments, recoveryof heat from the formation may combine injection of water andsubstantially non-reactive gas. For example, substantially non-reactivegas injection may be performed first, followed by water injection.

[1986] In some embodiments, the formation may be cooled such that anaverage temperature of the formation is at least below the ambientboiling temperature of water. Injection and recovery of fluid may berepeated until the average temperature of the formation is below theambient boiling point at the fluid pressure in the formation.

[1987]FIG. 334 illustrates a schematic of an embodiment of heat recoveryfrom a formation previously subjected to an in situ conversion process.FIG. 334 includes formation 8278 with heat recovery fluid injectionwellbore 8280 and production wellbore 8282. The wellbores may be membersof a larger pattern of wellbores placed throughout a portion of theformation. The temperature in heated portions of the formation that areto be cooled may be between about 300° C. and about 1000° C. Thermalenergy may be recovered from the heated portions of the formation byinjecting a heat recovery fluid. Heat recovery fluid 8284, such as waterand/or carbon dioxide, may be injected into wellbore 8280. A portion ofinjected water may be vaporized to form steam. A portion of injectedcarbon dioxide may adsorb on the surface of the carbon in the formation.Gas mixture 8286 may exit continuously from wellbore 8282. Gas mixture8286 may include the heat recovery fluid (e.g., steam or carbondioxide), hydrocarbons, and/or components. Components and hydrocarbonsmay be separated from the gas mixture in a surface facility. The heatrecovery fluid may be recycled back into the formation.

[1988] In an in situ conversion process embodiment, heat recovery fromthe formation may be performed in a batch mode. Injection of the heatrecovery fluid may continue for a period of time (e.g., until the porevolume of the portion of the formation is substantially filled). After aselected period of time subsequent to ceasing injection of heat recoveryfluid, gas mixture 8286 may be produced from the formation throughwellbore 8282. In an embodiment, the gas mixture may also exit throughwellbore 8280. The selected period of time may be, in some embodiments,about one month.

[1989] In one embodiment, gas mixture 8286 may be fed to surfaceseparation unit 8288. Separation unit 8288 may separate gas mixture 8286into heat recovery fluid 8290 and hydrocarbons and components 8296. Theheat recovery fluid may be used in power generation units 8292 or heatexchange mechanisms 8294. In another embodiment, gas mixture 8286 may befed directly from the formation to power generation units or heatexchange mechanisms. Injection of the heat recovery fluid may becontinued until a portion of the formation reaches a desiredtemperature. For example, if water is used as the heat recovery fluid,water injection may continue until the formation cools to, or is at atemperature below, the boiling point of water at formation pressure.

[1990] Thermal processing and increasing the permeability of a formationmay allow some components (e.g., hydrocarbons, metals and/or residualformation fluids) in the formation to migrate from a treatment area toareas adjacent to the formation. Such components may be created duringthermal processing of the formation. Such components may be present inhigher quantities if the formation is not subjected to a synthesis gasgeneration cycle after pyrolysis. In one embodiment, a recovery fluidmay be introduced into the formation to remove some of the components.The recovery fluid may be provided to the formation prior to and/orafter cooling of the formation has begun. The recovery fluid mayinclude, but is not limited to, water, steam, hydrogen, carbon dioxide,air, hydrocarbons (e.g., methane, ethane, and/or propane), and/or acombustible gas. The provided recovery fluid may be recycled fromanother portion of the formation, another formation, and/or the portionof the formation being treated. In some embodiments, a portion of therecovery fluid may react with one or more materials in the formation tovolatize and/or neutralize at least some of the material. In alternateembodiments, the recovery fluid may force components in the formation tobe produced. After production the recovery fluid may be provided to anenergy producing unit (e.g. turbine or combustor). For example, methanemay be provided to a portion of the formation. Heat within the formationmay transfer to the methane. The methane may cause production of amixture including heavier hydrocarbons (e.g., BTEX compounds). Themixture may be provided to a turbine, where some of the mixture iscombusted to produce electricity. In alternate embodiments, water may beprovided to the formation as a recovery fluid. Steam produced from thewater may entrain, distill, and/or drive components within the formationto production wells. In an embodiment, organic components may beproduced from the formation either by steam distillation and/orentrainment in steam. In some embodiments, inorganic components may beentrained and produced in condensed water in the formation. Waterinjection and steam recovery may be continued until safe and permissiblelevels of components are achieved. Removal of these components may occurafter an in situ conversion process is complete.

[1991] Remediation within a treatment area surrounded by a barrier(e.g., a frozen barrier) may inhibit the migration of components fromthe treatment area to the surrounding formation. A plurality of freezewells 8012 may be used to form frozen barrier zone 8002 and define avolume to be treated within hydrocarbon containing material 8006, asillustrated in FIG. 335. Frozen barrier 8002 may inhibit fluid flow intoor out of treatment area 6510. In an in situ conversion processembodiment, a recovery fluid may be introduced into the formation nearfreeze wells 8012 after treatment is complete. Injection wells 6902 usedfor injection of the recovery fluid may include, but are not limited to,pumping wells, heat sources, freeze wells, dewatering wells, and/orproduction wells that have been converted into injection wells. Incertain embodiments, wells used previously may have a sealed casing. Thesealed casing may be perforated to permit fluid communication betweenthe well and the surrounding formation. Recovery fluid may move some ofthe components in the formation towards one or more removal wells 6904.Removal wells 6904 may include wells that were converted from heatsources and/or production wells. In an alternate embodiment, a recoveryfluid may be introduced into a treatment area through an innermostproduction well, or a production well ring, that is converted into aninjection well.

[1992] In some embodiments, the recovery fluid may be introduced intothe formation after the frozen barrier zone has been partially thawed.When thawing the frozen barrier, thermal energy may be removed from thefrozen barrier by circulating various fluids through the freeze well.For example, a warm refrigerant may be injected into the freeze wellsystem to be cooled and used in a surface treatment unit, a freeze wellsystem, and/or other treatment area. As the temperature within thefreeze well increases, various other fluids (e.g., water, substantiallynon-reactive gas, etc.) may be utilized to raise the temperature of thefreeze well. Thawed freeze wells that are exposed may be converted foruse as injection wells 6902 to introduce recovery fluid into theformation. Introduction of the recovery fluid may heat the regionadjacent to the inner row of freeze wells to an average temperature ofless than a pyrolysis temperature of hydrocarbon material in theformation. The heat from the recovery fluid may move mobilizedhydrocarbon and inorganic components. Movement of the hydrocarbon andinorganic components may be due in part to steam distillation of thefluids and/or entrainment. Introducing the recovery fluid at a pointwhere the formation was previously frozen ensures that the hydrocarbonmaterial at the injection well is unaltered. The unaltered hydrocarbonmaterial may be essentially in its original natural state. As such, theinjected fluid may move from a natural zone to the previously treatedarea and be produced. Thus, fluids formed during the treatment areremoved without spreading such fluids to other areas outside of thetreatment area. Alternatively, any well previously frozen in a frozenbarrier zone, such as a pumping well, may be thawed and used as aninjection well.

[1993] A volume of recovery fluid required to remediate a treatment areamay be greater than about one pore volume of the treatment area. Twopore volumes or more of recovery fluid may be introduced to remediatethe treatment area. In certain embodiments, injection of a recoveryfluid to remediate a treatment area may continue until concentrations ofcomponents in the removed recovery fluid are at acceptable levels deemedappropriate for a site. These acceptable levels may be based on baseline surveys, regulatory requirements, future potential uses of thesite, geology of the site, and accessibility. After one or morecomponents within a treatment area are removed or reduced to acceptablelevels, the treatment system for the formation, including the freezewells, may be deactivated. If a new barrier zone around a new treatmentarea is to be formed, heat may be transferred between hydrocarboncontaining material, in which a new barrier zone is to be formed, andthe initial freeze wells using a circulated heat transfer fluid. Usingdeactivated freeze wells to cool hydrocarbon containing material inwhich a low temperature zone is to be formed may allow for recovery ofsome of the energy expended to form and maintain the initial barrier. Inaddition, using thermal energy extracted from the initial barrier tocool hydrocarbon material in which a new barrier zone is to be formedmay significantly decrease a cost of forming the new barrier. In sometreatment system embodiments, a low temperature zone may be allowed toreach thermal equilibrium with a surrounding formation naturally.

[1994] In some in situ conversion process embodiments, the frozenbarrier may include an inner ring of freeze wells directly adjacent tothe treatment area and an outer ring of freeze wells directly adjacentto the untreated area. A region of the formation near the freeze wellsmay remain at a temperature below the freezing point of water duringpyrolysis and synthesis gas generation. In an embodiment, organiccomponents from pyrolysis may migrate through thermal fractures to aregion adjacent to the inner row of freeze wells. The contaminants maybecome immobilized in fractures and pores in the region due to therelatively low temperatures of the region.

[1995] Migration of contaminants from the treatment area may be reducedor prevented by inhibiting groundwater flow through the treatment area.For example, groundwater flow may be inhibited using a barrier such as afreeze wall and/or sulfur barriers. As a result, migration ofcontaminants may be reduced or eliminated even if contaminants weredissolved in formation pore water. In addition, it may be advantageousto inhibit groundwater flow to maintain a reduced state within theformation. Oxidized metals introduced into the formation fromgroundwater flow tend to have greater mobility and may be more likely tobe released.

[1996] An embodiment for inhibiting migration of contaminants may alsoinclude sealing off the mineral matrix and residual carbon byprecipitation or evaporation of a sealing mineral phase. The sealingmineral phase may inhibit dissolution of contaminants of fluids in theformation into groundwater.

[1997] Carbon dioxide may be produced during an in situ conversionprocess or during processing of the products produced by the in situconversion process (e.g., combustion). Control and/or reduction ofcarbon dioxide production from an in situ conversion process may bedesirable. “Carbon dioxide life cycle emissions,” as used herein, isdefined as the amount of CO₂ emissions from a product as it is produced,transported, and used.

[1998] A base line CO₂ life cycle emission level may be selected forproducts produced from an in situ conversion process. The formationconditions and/or process conditions may be altered to produce productsto meet the selected CO₂ base line life cycle emission level. In someembodiments, in situ conversion products may be blended to meet aselected CO₂ base line life cycle emission level. The CO₂ life cycleemission level of a selected product is defined as a number of kilogramsof CO₂ per joule of energy (kg CO₂/J).

[1999] A hydrogen cycle, a half-way cycle, and a methane cycle areexamples of processes that may be used to produce products with selectedCO₂ emission levels less than the total CO₂ emission level that would beproduced by direct production of natural gas from a gas reservoir. Incertain embodiments, products may be combined to produce a product witha selected CO₂ emission level less than the total CO₂ emission fromdirect production of natural gas. In other embodiments, cycles may beblended to produce products with a CO₂ emission level less than thetotal CO₂ emission from direct production of natural gas. For example,in an embodiment, a methane cycle may be used in one part of aproduction field and a half-way cycle may be used in another part of theproduction field. The products produced from these two processes may beblended to produce a product with a selected CO₂ emission level. Inother embodiments, other combinations of products from the hydrogencycle, the half-way cycle, and the methane cycle may be used to producea product with a selected CO₂ emission level.

[2000] In an in situ conversion process embodiment, a formation may betreated such that hydrocarbons in the formation are converted to adesired product. The product may be produced from the formation. In somein situ conversion process embodiments, the in situ conversion processmay be operated to produce a limited amount of carbon dioxide.

[2001] In an in situ conversion process embodiment, the in situconversion process may be operated so that a substantial portion of theproduct is molecular hydrogen. There may be little or no hydrocarbonfluid recovery. An in situ conversion process that operates at a hightemperature to produce a substantial portion of hydrogen may be a“hydrogen cycle process.”

[2002] A portion of the hydrogen produced during the hydrogen cycleprocess may be used to fuel heat sources that raise and/or maintain atemperature within the formation to a high temperature.

[2003] During a hydrogen cycle process, a production well and formationadjacent to the production well may be heated to temperatures greaterthan about 525° C. At such temperatures, a substantial portion ofhydrocarbons present or that flow into the production well and formationadjacent to the production well may be reduced to hydrogen and coke.There may be minimal or no production of carbon dioxide or hydrocarbons.Hydrocarbons in formation fluid produced from the formation may berecycled back into the formation through injection wells to producehydrogen and coke. Hydrogen produced from a hydrogen cycle process maybe produced through heated production wells in the formation. A portionof the produced hydrogen may be used as a fuel for heat sources in theformation. A portion of the hydrogen may be sold or used in fuel cells.In some embodiments, coke produced during a hydrogen cycle process mayslowly fill pore space within the formation adjacent to the productionwell. The coke may provide structural strength to the formation. In someembodiments, the production wells may be treated (e.g., by introducingsteam to generate synthesis gas) to remove a portion of formed coke andallow for production of formation fluid. In some embodiments, a cokedproduction well may be blocked, and formation fluid may be produced fromother production wells.

[2004] A hydrogen cycle may allow for very low CO₂ life cycle emissionlevels. In some embodiments, a hydrogen cycle process may have a CO₂life cycle emission level of about 3.3×10⁻⁹ kg CO₂/J. In otherembodiments, a CO₂ life cycle emission level of the hydrogen cycleprocess may be less than about 1.6×10×10⁻kg CO₂/J.

[2005] In an in situ conversion process embodiment, a portion offormation may be treated to produce a product that is substantially amixture of molecular hydrogen and methane. There may be little or noother hydrocarbons (i.e., ethane, propane, etc.). A process ofconverting hydrocarbons in a formation to a product that issubstantially molecular hydrogen and methane may be referred to as a“half-way cycle process.” A portion of the product may be used as a fuelfor heat sources that heat the formation to maintain and/or increase theformation temperature.

[2006] During a half-way cycle, production wells and formation adjacentto the production wells may be heated to temperatures from about 400° C.to about 525° C. A substantial portion of hydrocarbons present or thatflow into the production wells or formation adjacent to the productionwells may be reduced to molecular hydrogen and methane. The hydrogen andmethane may be produced as a mixture from the production wells. Producedhydrocarbons having carbon numbers greater than one may be recycled backinto the formation through injection wells to generate hydrogen andmethane. Formation adjacent to the production wells may slowly coke upduring a half-way cycle. When production through a production well fallsbelow a certain level, the production well may blocked in. In someembodiments, the production well may be treated (e.g., by introducingsteam to generate synthesis gas) to remove a portion of the coke andallow for increased production through the well.

[2007] In an embodiment of a half-way cycle process, produced hydrogenand methane may be separated from other produced fluid. A portion of thehydrogen and methane may be used as a fuel for heat sources. Further,hydrogen may be separated from the methane of a portion not used asfuel. In some embodiments, a portion of the hydrogen may be used forhydrogenation in another portion of the formation and/or in surfacefacilities. In some embodiments, hydrogen may be sold. In someembodiments, some or all produced methane may be used to fuel heatsources.

[2008] A mixture produced using a half-way cycle may have a CO₂ lifecycle emission level that is greater than a CO₂ life cycle emissionlevel of a hydrogen cycle. A mixture produced using a half-way cycle mayhave a CO₂ life cycle emission level of less than about 3.3×10⁻⁸ kgCO₂/J.

[2009] In an in situ conversion process embodiment, a portion offormation may be treated to produce a product that is substantiallymethane. A process of converting a substantial portion of hydrocarbonswithin a portion of formation to methane may be referred to as a“methane cycle.”

[2010] The producing wellbore and the formation proximate the producingwellbore may, in some embodiments, be heated to temperatures from about300° C. to about 500° C. For example, the producing wellbore may beheated to about 400° C. Pyrolysis in this temperature range may allow asubstantial portion of hydrocarbons in the formation to be converted tomethane. Hydrocarbons with carbon numbers greater than one produced fromthe formation may be recycled back into the formation through injectionwells to generate methane. The methane may be produced in a mixture fromthe heated wellbores. In an embodiment, the methane content may begreater than about 80 volume % of the produced fluids.

[2011] A mixture produced from a methane cycle may have a CO₂ life cycleemission level that is larger than the CO₂ life cycle emission level fora half-way cycle. In some embodiments of methane cycles, the CO₂ lifecycle emission levels are less than about 7.4×10⁻⁸ kg CO₂/J.

[2012] In an in situ conversion process embodiment, molecular hydrogenmay be produced on site using processes such as, but not limited to,Modular and Intensified Steam Reforming (MISR) and/or Steam MethaneReforming (SMR). The produced molecular hydrogen may be blended withother products to produce a product below a selected CO₂ emission level.The CO₂ produced using MISR or other processes may be sequestered in aformation.

[2013] After completion of pyrolysis and/or synthesis gas generationduring an in situ conversion process, at least a portion of theformation may be converted into a hot spent reservoir. The hot spentreservoir may have a temperature of greater than about 350° C. Theporosity may have increased by 20 volume % or more. In addition, apermeability in a hot spent reservoir may be greater than about 1 darcy,or in certain embodiments, greater than about 20 darcy. A hot spentreservoir may have a large open volume. The surface area within thevolume may have increased significantly due to the in situ conversionprocess. Utilization of the in situ conversion process may have requiredthe installation and use of production wells and heat sources spaced ata range between about 10 m and about 30 m. A barrier (e.g., freezewells) may also be present to inhibit migration of fluids to or from atreatment area in the formation.

[2014] In an in situ conversion process embodiment, a heated formation(e.g., a formation that has undergone substantial pyrolysis and/orsynthesis gas generation) may be used to produce olefins and/or otherdesired products. Hydrocarbons may be provided to (e.g., injected into)a heated portion of a formation. An in situ conversion process in aseparate portion of the formation may provide the source of thehydrocarbons. The formation temperature and/or pressure may becontrolled to produce hydrocarbons of a desired composition (e.g.,hydrocarbons with a C₂-C₇ carbon chain length). Temperature may becontrolled by controlling energy input into heat sources. Pressure maybe controlled by controlling the temperature in the formation and/or bycontrolling a rate of production of formation fluid from the formation.Pressure within a portion of a formation enclosed by a perimeter barrier(e.g., a frozen barrier and an impermeable overburden and underburden)may be controlled so that the pressure is substantially uniformthroughout the enclosed portion of formation.

[2015] Many different types of hydrocarbons may be provided to theheated formation as a feed stream. Examples of hydrocarbons include, butare not limited to, pitch, heavy hydrocarbons, asphaltenes, crude oil,naphtha, and/or condensable hydrocarbons (e.g., methane, ethane,propane, and butane). A portion of heavy and/or condensable hydrocarbonsintroduced into a heated portion of the formation may pyrolyze to formshorter chain compounds. The shorter chain compounds may have greatervalue than the longer chain compounds introduced into the portion offormation.

[2016] A portion of the hydrocarbons introduced into the formation mayreact to form olefins. An overall efficiency for producing olefins maybe relatively low (as compared to reactors designed to produce olefins),but the volume of heated formation and/or the availability of feed fromportions of the formation undergoing an in situ conversion process maymake production of olefins from a heated formation economically viable.

[2017] In certain embodiments, the temperature of a selected portion ofthe formation (e.g., near production wells) may be controlled so thathydrocarbon fluid flowing into the selected portion has an increasedchance of forming olefins. In certain embodiments, process conditionsmay be controlled such that the time period in which the compounds aresubjected to relatively higher temperatures is controlled. In certainembodiments, only a small portion of the formation (e.g., near theproduction wells) is at a high enough temperature to promote olefinformation. Olefins may be formed subsurface in the small portion, butthe olefins are produced quickly (e.g., before the olefins cancross-link in the formation and/or further react to form coke).

[2018] In an embodiment, olefins are produced from saturatedhydrocarbons. Formation of the olefins from saturated hydrocarbons alsoresults in the production of molecular hydrogen. In an embodiment,olefin production may include cracking saturated hydrocarbons in theformation and allowing the cracked hydrocarbons to further react in theformation (e.g., via alkylation or dimerization). The formation ofolefins may involve different reaction mechanisms. Any number of theolefin formation mechanisms may be present in the in situ conversionprocess. Water may be added to the formation for steam generation and/ortemperature control.

[2019] Examples of olefins produced by providing hydrocarbons to aheated formation may include, but are not limited to, ethene, propene,1-butene, 2-butene, higher molecular weight olefins, and/or mixturesthereof. The produced mixture may include from slightly over about 0weight % to about 80 weight % (e.g., from about 10-50 weight %) olefinsin a hydrocarbon portion of a produced mixture.

[2020] In an in situ conversion process embodiment, crude oil may beprovided to a heated portion of a formation. The crude oil may crack inthe heated portion to form a lighter, higher quality oil and an olefinportion. In an in situ conversion process embodiment, pitch and/orasphaltenes may be provided to a heated portion of a formation. Thepitch and/or asphaltenes may be in solution and/or entrained in asolvent. The solvent may be a hydrocarbon portion of a fluid producedfrom a portion of a formation subjected to an in situ conversionprocess. A portion of the pitch and/or asphaltenes and the solvent maybe converted in the formation to high quality hydrocarbons and/orolefins. Similarly, emulsions, bottoms, and/or undesired hydrocarboncompounds that are flowable, entrained in a flowable solution, ordissolved in a solvent may be introduced into a heated portion of aformation to upgrade the introduced fluids and/or produce olefins.

[2021] In some embodiments, a temperature in selected portions of aproduction well wellbore may be controlled to promote production ofolefins. A portion of the wellbore adjacent to a heated portion of theformation may include a heater that maintains the temperature at anelevated temperature. A portion of the wellbore above the heated portionof the wellbore may include a heat transfer line that reduces thetemperature of fluid being removed through the wellbore to a temperaturebelow reaction temperatures of desired components within the wellbore(e.g., olefins). In some embodiments, transfer of heat from the fluidsin the wellbore to the overburden may reduce the temperature of fluidsin the wellbore quickly enough to obviate the need for a heat transferline in the wellbore.

[2022] In some in situ conversion process embodiments, hydrocarbonfeedstock introduced into a hot portion of a portion may have an APIgravity of less than about 20°. The hydrocarbon feedstock may be crackedin the heated portion to produce a plurality of products. The productsmay include olefins. Molecular hydrogen may also be produced along witha mixture of products. A temperature and/or a pressure of the heatedportion of the formation may be controlled such that a substantialportion of the produced product includes olefins. A hydrocarbon portionof the produced mixture may include from about 1 weight % to about 80weight % (e.g., from about 10-50 weight %) olefins.

[2023] In some in situ conversion process embodiments, a hydrocarbonmixture produced from a formation may be suitable for use as an olefinplant feedstock. Process conditions in a portion of a formation may beadjusted to produce a hydrocarbon mixture that is suitable for use as anolefin plant feedstock. The mixture should contain relatively shortchain saturated hydrocarbons (e.g., methane, ethane, propane, and/orbutane). To change formation conditions to produce a hydrocarbon mixturesuitable for use as an olefin plant feedstock, backpressure within theformation may be maintained at an increased level (i.e., production fromproduction wells may be low enough to result in an increase in pressurein the formation).

[2024] In some in situ conversion process embodiments, low molecularweight olefins (e.g., ethene and propene) may be produced during the insitu conversion process. Fluid produced may be routed through arelatively hot (e.g., greater than about 500° C.) subsurface zone beforethe fluid is allowed to cool. The fluid may crack at a high temperatureto produce low molecular weight olefins. Temperature of the fluid shouldbe subjected to high temperature for only a short period of time toinhibit formation of methane, hydrogen, and/or coke from the lowmolecular weight olefins.

[2025] In some in situ conversion process embodiments, olefin productionyield may be facilitated from a formation. Continued processing orrecycling of the non-olefinic C₂+ products in the in situ conversionprocess may maximize ethene and/or propene yield. Control of thetemperature and residence time within a portion of the formation may beused to maximize non-olefinic C₂+ hydrocarbons and hydrogen content.Some olefins may be produced in this cycle and separated from theproduced fluid. The non-olefinic portion may be recycled to a secondsection of the formation that includes production wells that are heated.A portion of the introduced hydrocarbons may be converted into olefinsby the heated production wells to increase the yield of olefins obtainedfrom the formation.

[2026] Some in situ conversion processes may be run at sufficientpressure to generate a desirable steam cracker feed. A desirable steamcracker feed may be a feed with relatively high hydrocarbon content(e.g., a relatively high alkane content) and relatively low oxygen,sulfur, and/or nitrogen content. A desirable steam cracker feed mayreduce the need to treat the stream before processing in a steam crackerunit. Therefore, the desirable feed may be run directly from the in situconversion process to a steam cracker unit. The steam cracker unit mayproduce olefins from the feed stream.

[2027] In an in situ conversion process embodiment, a heated formationmay be used to upgrade materials. Materials to be upgraded may beproduced from the same portion of the formation and recycled, producedfrom other formations, or produced from other portions of the sameformation.

[2028] During some in situ conversion process embodiments in selectedformations (e.g., in tar sands formations), only a selected portion of aformation may be heated to relatively high temperatures (e.g., atemperature sufficient to cause pyrolysis). Other portions of theformation may still produce heavy hydrocarbons but may not be heated, ormay only be partially heated (e.g., by steam, heat sources, or othermechanisms). The heavy hydrocarbons produced from the other less heatedor unheated portions of the formation may be introduced into the portionof the formation that is heated to a relatively high temperature. Thehigh temperature portion of the formation may upgrade the introducedheavy hydrocarbons. Energy savings may be achieved since only a portionof the formation is heated to a relatively high temperature.

[2029] In an embodiment, surface mined tar (e.g., from tar sands) may beupgraded in a heated formation. The tar sands may be processed toproduce separated hydrocarbons (e.g., tar). A portion of the tar may beheated, entrained, and/or dissolved in a solvent to produce a flowablefluid. The solvent may be a portion of hydrocarbon fluid produced fromthe formation. The flowable fluid may be introduced into the heatedportion of the formation.

[2030] Emulsions may be produced during some metal processing and/orhydrocarbon processing procedures. Some emulsions may be flowable. Otheremulsions may be made flowable by the introduction of heat and/or acarrier fluid. The carrier fluid may be water and/or hydrocarbon fluid.The hydrocarbon fluid may be a fluid produced during an in situ process.A flowable emulsion may be introduced into a heated portion of aformation being subjected to in situ processing. In some embodiments,the heated portion may break the emulsion. The components of theemulsion may pyrolyze or react (e.g., undergo synthesis gas reactions)in the heated formation to produce desired products from productionwells. In some embodiments, the emulsion or components of the emulsionmay remain in the formation.

[2031] Upgrading may include, but is not limited to, changing a productcomposition, a boiling point, or a freezing point. Examples of materialsthat may be upgraded include, but are not limited to, heavyhydrocarbons, tar, emulsions (e.g., emulsions from surface separation oftar from sand), naphtha, asphaltenes, and/or crude oil. In certainembodiments, surface mined tar may be injected into a formation forupgrading. Such surface mined tar may be partially treated, heated, oremulsified before being provided to a formation for upgrading. Thematerial to be upgraded may be provided to the heated portion of theformation. The material may be upgraded in the formation. For example,upgrading may include providing heavy hydrocarbons having an API gravityof less than about 20°, 15°, 10°, or 5° into a heated portion of theformation. The heavy hydrocarbons may be cracked or distilled in theheated portion. The upgraded heavy hydrocarbons may have an API gravityof greater than about 20° (or above about 25° or above 30°). Theupgraded heavy hydrocarbons may also have a reduced amount of sulfurand/or nitrogen. A property of the upgraded hydrocarbons (e.g., APIgravity or sulfur content) may be measured to determine the relativeupgrading of the hydrocarbons.

[2032] In some in situ conversion process embodiments, fluid producedfrom a formation may be fractionated in an above ground facility toproduce selected components. The relatively heavier molecular weightcomponents (e.g., bottom fractions from distillation columns) may berecycled into a formation. The heated formation may upgrade therelatively heavier molecular weight components.

[2033] In some in situ conversion process embodiments, heavyhydrocarbons may be produced at a first location. The heavy hydrocarbonsmay be diluted with a diluent to enable the heavy hydrocarbons to bepumped or otherwise transported to a different location. The mixture ofheavy hydrocarbons and diluent may be separated at the heated formationprior to providing the heavy hydrocarbons mixture to the heatedformation for upgrading. Alternately, the mixture of heavy hydrocarbonsand diluent may be directly injected into a heated formation forupgrading and separation in the heated formation. In certainembodiments, a hot fluid (e.g., steam) may be added to the heavyhydrocarbons mixture to allow fluid cracking in the heated formation.Steam may inhibit coking in the formation, lessen the partial pressureof hydrocarbons in the formation, and/or provide a mechanism to sweepthe formation. Controlling the flow of steam may provide a mechanism tocontrol the residence time of the hydrocarbons in the heated formation.The residence time of the hydrocarbons in the heated formation may beused to control or adjust the molecular weight and/or API gravity of aproduct produced from the heated formation.

[2034] In an in situ conversion process embodiment, heavy hydrocarbonsmay be produced from a heated formation. The heavy hydrocarbons may berecycled back into the same formation to be upgraded. The upgradedproducts may be produced from the formation. In another embodiment, theheavy hydrocarbon may be produced from one formation and upgraded inanother formation at a different temperature. The residence time andtemperature of the formation may be controlled to produce a desirableproduct. For example, a portion of fluid initially produced from a tarsands formation undergoing an in situ conversion process may be heavyhydrocarbons, especially if the hydrocarbons are produced from arelatively deep depth within a hydrocarbon containing layer of the tarsands formation. The produced heavy hydrocarbons may be reintroducedinto the formation through or adjacent to a heat source to facilitateupgrading of the heavy hydrocarbons.

[2035] In an in situ conversion process embodiment, crude oil producedfrom a formation by conventional methods may be upgraded in a heatedformation of the in situ conversion process system. The crude oil may beprovided to a heated portion of the formation to upgrade the oil. Insome embodiments, only a heavy fraction of the crude oil may beintroduced into the heated formation. The heated portion of theformation may upgrade the quality of the introduced portion of the oiland/or remove some of the undesired components within the introducedportion of the crude oil (e.g., sulfur and/or nitrogen).

[2036] In some embodiments, hydrogen or any other hydrogen donor fluidmay be added to heavy hydrocarbons injected into a heated formation. Thehydrogen or hydrogen donor may increase cracking and upgrading of theheavy hydrocarbons in the heated formation. In certain embodiments,heavy hydrocarbons may be injected with a gas (e.g., hydrogen or carbondioxide) to increase and/or control the pressure within the heatedformation.

[2037] In an in situ conversion process embodiment, a heated portion ofa formation may be used as a hydrotreating zone. A temperature andpressure of a portion of the formation may be controlled so thatmolecular hydrogen is present in the hydrotreating zone. For example, aheat source or selected heat sources may be operated at hightemperatures to produce hydrogen and coke. The hydrogen produced by theheat source or selected heat sources may diffuse or be drawn by apressure gradient created by production wells towards the hydrotreatingzone. The amount of molecular hydrogen may be controlled by controllingthe temperature of the heat source or selected heat sources. In someembodiments, hydrogen or hydrogen generating fluid (e.g., hydrocarbonsintroduced through or adjacent to a hot zone) may be introduced into theformation to provide hydrogen for the hydrotreating zone.

[2038] In an in situ conversion process embodiment, a compound orcompounds may be provided to a hydrotreating zone to hydrotreat thecompound or compounds. In some embodiments, the compound or compoundsmay be generated in the formation by pyrolysis reactions of nativehydrocarbons. In other embodiments, the compound or compounds may beintroduced into the hydrotreating zone. Examples of compounds that maybe hydrotreated include, but are not limited to, oxygenates, olefins,nitrogen containing carbon compounds, sulfur containing carboncompounds, crude oil, synthetic crude oil, pitch, hydrocarbon mixtures,and/or combinations thereof.

[2039] Hydrotreating in a heated formation may provide advantages overconventional hydrotreating. The heated reservoir may function as a largehydrotreating unit, thereby providing a large reactor volume in which tohydrotreat materials. The hydrotreating conditions may allow thereaction to be run at low hydrogen partial pressures and/or at lowtemperatures (e.g., less than about 0.007 to about 1.4 bars or about0.14 to about 0.7 bars partial pressure hydrogen and/or about 200° C. toabout 450° C. or about 200° C. to about 250° C.). Coking within theformation generates hydrogen, which may be used for hydrotreating. Eventhough coke may be produced, coking may not cause a decrease in thethroughput of the formation because of the large pore volume of thereservoir.

[2040] The heated formation may have lower catalytic activity forhydrotreating compared to commercially available hydrotreatingcatalysts. The formation provides a long residence time, large volume,and large surface area, such that the process may be economical evenwith lower catalytic activity. In some formations, metals may bepresent. These naturally present metals may be incorporated into thecoke and provide some catalytic activity during hydrotreating.Advantageously, a stream generated or introduced into a hydrotreatingzone does not need to be monitored for the presence of catalystdeactivators or destroyers.

[2041] In an embodiment, the hydrotreated products produced from an insitu hydrotreating zone may include a hydrocarbon mixture and aninorganic mixture. The produced products may vary depending upon, forexample, the compound provided. Examples of products that may beproduced from an in situ hydrotreating process include, but are notlimited to, hydrocarbons, ammonia, hydrogen sulfide, water, or mixturesthereof. In some embodiments, ammonia, hydrogen sulfide, and/oroxygenated compounds may be less than about 40 weight % of the producedproducts.

[2042] In an in situ conversion process embodiment, a heated formationmay be used for separation processes. FIG. 336 illustrates an embodimentof a temperature gradient formed in a selected section of heatedformation 8501. Formation temperatures may decrease radially from heatsource 8500 through the selected section. A fluid (either products fromvarious surface processes and/or products from other sources such ascrude oil) may be provided through injection well 8502. The fluid maypass through heated formation 8501. Some production wells 8503 may belocated at various positions along the temperature gradient. For vaporphase production wells, different products may be produced fromproduction wells that are at different temperatures. The ability toproduce different compositions from production wells depending on thetemperature of the production well may allow for production of a desiredcomposition from selected wells based on boiling points of fluids withinthe formation. Some compounds with boiling points that are below thetemperature of a production well may be entrained in vapor and producedfrom the production well.

[2043]FIG. 337 illustrates an embodiment for separating hydrocarbonmixtures in a heated portion of formation 8506. Temperature and/orpressure of the heated portion may be controlled by heat source 8504. Ahydrocarbon mixture may be provided through injection well 8505 into aportion of the formation that is cooler than a portion of the formationcloser to heat sources or production wells. In a cooler portion offormation 8506, relatively heavy molecular weight products may condenseand remain in the formation. After separation of a desired quantity ofhydrocarbon mixture, the cooler portion of the formation may be heatedto result in pyrolysis of a portion of the heavy hydrocarbons to desiredproducts and/or mobilization of a portion of the heavy hydrocarbons toproduction well 8507.

[2044] In an embodiment, a portion of a formation may be shut in atselected times to provide control of residence time of the products inthe subsurface formation. Shutting in a portion of the formation by notproducing fluid from production wells may result in an increase inpressure in the formation. The increased pressure may result inproduction of a lighter fluid from the formation when production isresumed. Different products may be produced based on the residence timeof fluids in the formation.

[2045] Once a formation has undergone an in situ conversion process,heat from the process may remain within the formation. Heat may berecovered from the formation using a heat transfer fluid. Heat transferfluids used to recover energy from a relatively permeable formation mayinclude, but are not limited to, formation fluids, product streams(e.g., a hydrocarbon stream produced from crude oil introduced into theformation), inert gases, hydrocarbons, liquid water, and/or steam. FIG.338 illustrates an embodiment for recovering heat remaining in formation8509 by providing a product stream through injection well 8510. Heatremaining in the formation may transfer to the product stream. Theformation heat may be controlled with heat source 8508. The heatedproduct stream may be produced from the formation through productionwell 8511. The heat of the product stream may be transferred to anynumber of surface treatment units 8512 or to other formations.

[2046] In an in situ conversion process embodiment, heat recovered fromthe formation by a heat transfer fluid may be directed to surfacetreatment units to utilize the heat. For example, a heat transfer fluidmay flow to a steam-cracking unit. The heat transfer fluid may passthrough a heat exchange mechanism of the steam-cracking unit to transferheat from the heat transfer fluid to the steam-cracking unit. Thetransferred heat may be used to vaporize water or as a source of heatfor the steam-cracking unit.

[2047] In some in situ conversion process embodiments, heat transferfluid may be used to transfer heat to a hydrotreating unit. The heattransfer fluid may pass through a heat exchange mechanism of thehydrotreating unit. Heat from the product stream may be transferred fromthe heat transfer fluid to the hydrotreating unit. Alternatively, atemperature of the heat transfer fluid may be increased with a heatingunit prior to processing the heat transfer fluid in a steam crackingunit or hydrotreating unit. In addition, heat of a heat transfer fluidmay be transferred to any other type of unit (e.g., distillation column,separator, regeneration unit for an activated carbon bed, etc.).

[2048] Heat from a heated formation may be recovered for use in heatinganother formation. FIG. 339 illustrates an embodiment of a heat transferfluid provided through injection well 8515 into heated formation 8514.Heat may transfer from the heated formation to the heat transfer fluid.Heat source 8513 may be used to control formation heat. The heattransfer fluid may be produced from production well 8516. The heattransfer fluid may be directed through injection well 8517 to transferheat from the heat transfer fluid to formation 8518. Formationconditions subsequent to an in situ conversion process may determine theheat transfer fluid temperature. The heat transfer fluid may be producedfrom production well 8519. In some embodiments, formation 8518 mayinclude U-tube wells or closed casings with fluid insertion ports andfluid removal ports so that heat transfer fluid does not enter into therock of the formation.

[2049] Movement of the heat transfer fluid (e.g., product streams, inertgas, steam, and/or hydrocarbons) through the formation may be controlledsuch that any associated hydrocarbons in the formation are directedtowards the production wells. The formation heat and mass transfer ofthe heat transfer fluid may be controlled such that fluids within theformation are swept towards the production wells. During remediation ofa formation, the formation heat and mass transfer of the heat transferfluid may be controlled such that transfer of heat from the formation tothe heat transfer fluid is accomplished simultaneously with clean up ofthe formation.

[2050]FIG. 340 illustrates an in situ conversion process embodiment inwhich a heat transfer fluid is provided to formation 8521 a throughinjection well 8522. Heat within formation 8521 a may be controlled byheat source 8520. The heat of the heat transfer fluid may be transferredto cooler formation 8521 b. The heat transfer fluid may be producedthrough production well 8523. In other embodiments, a heat transferfluid may be directed to a plurality of formations to heat the pluralityof formations.

[2051]FIG. 341 illustrates an embodiment for controlling formation 8525a to produce region of reaction 8525 b in the formation. A region ofreaction may be any section of the formation having a temperaturesufficient for a reaction to occur. A region of reaction may be hotteror cooler than a portion of a formation proximate the region ofreaction. Material may be directed to the region of reaction throughinjection well 8526. The material may be reacted within the region ofreaction. Any number and any type of heat source 8524 may heat theformation and the region of reaction. Appropriate heat sources include,but are not limited to, electric heaters, surface burners, flamelessdistributed combustors, and/or natural distributed combustors. Theproduct may be produced through production well 8527.

[2052] In some in situ conversion process embodiments, a region ofreaction may be heated by transference of heat from a heated product tothe region of reaction. In some embodiments, regions of reaction may bein series. A material may flow through the regions of reaction in aserial manner. The regions of reaction may have substantially the sameproperties. As such, flowing a material through such regions of reactionmay increase a residence time of the material in the regions ofreaction. Alternatively, the regions of reaction may have differentproperties (e.g., temperature, pressure, and hydrogen content). Flowinga material through such regions of reaction may include performingseveral different reactions with the material. Various materials may bereacted in a region of reaction. Examples of such materials include, butare not limited to, materials produced by an in situ conversion processand hydrocarbons produced from petroleum crude (e.g., tar, pitch,asphaltenes, heavy hydrocarbons, naphtha, methane, ethane, propane,and/or butane).

[2053] In some in situ conversion process embodiments, a region ofreaction may be formed by placing conduit 8530 in a heated portion offormation 8529. FIG. 342 depicts such an embodiment of an in situconversion process. A portion of conduit 8530 may be heated by theformation to form a region of reaction within the conduit. The conduitmay inhibit contact between the material and the formation. Theformation temperature and conduit temperature may be controlled by heatsource 8528. Material may be provided through injection well 8531. Thematerial may be produced through production well 8532.

[2054] A shape of a conduit may be variable. For example, the conduitmay be curved, straight, or U-shaped (as shown in FIG. 343). U-shapedconduit 8534 may be placed within a heater well in a heated formation.Any number of materials may be reacted within the conduit. For example,water may be passed through a conduit such that the water is heated to atemperature higher than the initial water temperature. In otherembodiments, water may be heated in a conduit to produce steam. Materialmay be provided through injection site 8535 and produced throughproduction site 8536. The formation temperature may be controlled byheat source 8533.

[2055] In some in situ conversion process embodiments, formations may beused to store materials. A first portion of a formation may be subjectedto in situ conversion. After in situ conversion, the first portion maybe permeable and have a large pore volume. Formation fluid (e.g.,pyrolysis fluid or synthesis gas) produced from another portion of theformation may be stored in the first portion. Alternately, the firstportion may be used to store a separated component of formation fluidproduced from the formation, a compressed gas (e.g., air), crude oil,water, or other fluid. Alternately, the first portion may be used tostore carbon dioxide or other fluid that is to be sequestered.

[2056] Materials may be stored in a portion of the formation temporarilyor for long periods of time. The materials may include inorganic and/ororganic compounds and may be in solid, liquid, and/or gaseous form. Ifthe materials are solids, the solid products may be stored as a liquidby dissolving the materials in a suitable solvent. If the materials areliquids or gases, they may be stored in such form. The materials may beproduced from the formation when needed. In some storage embodiments,the stored material may be removed from the formation by heating theformation using heat sources inserted in wellbores in the formation andproducing the stored material from production wells. The heat sourcesmay be heat sources used during a pyrolysis and/or synthesis gasgeneration phase of the in situ conversion process. The production wellsmay be production wells used during the pyrolysis and/or synthesis gasgeneration phase of the in situ conversion process. In otherembodiments, the heat source and/or production wells may be wells thatwere originally used for a different purpose and converted to a newpurpose. In some embodiments, some or all heat source and/or productionwells may be newly formed wells in the storage portion of the formation.

[2057] In a storage process embodiment, oil may be stored in a portionof a formation that has been subjected to an in situ conversion process.In some embodiments, natural gas may be stored in a portion of aformation that has been subjected to an in situ conversion process. Ifthe formation is close to the surface, the shallow depth of theformation may limit gas pressure. In certain embodiments, close spacingof wells may provide for rapid recovery of oil and/or natural gas withhigh efficiency.

[2058] In a storage process embodiment, compressed air may be stored ina portion of a formation that has been subjected to an in situconversion process. The stored compressed air may be used for peak powergeneration, load leveling, and/or to even out and compensate for thevariability of renewable power sources (e.g., solar and/or wind power).A portion of the stored compressed air may be used as an oxygen sourcefor a natural distributed combustor, flameless distributed combustor,and/or a surface burner.

[2059] In an in situ conversion process embodiment, water may beprovided to a hot formation to produce steam. The water may be appliedduring pyrolysis to help remove coke adjacent to or on heat sourcesand/or production wells. Water may also be introduced into the formationafter pyrolysis and/or synthesis gas generation is complete. Theproduced steam may sweep hydrocarbons towards production wells. Theformation heat transfer and mass transfer may be controlled to clean theformation during recovery of heat from the formation. The introducedwater may absorb heat from the formation as the water is transformed tosteam, resulting in cooling of the formation. The steam may be producedfrom the formation. Organic or other components in the steam may beseparated from the steam and/or water condensed from the steam. Thesteam may be used as a heat transfer fluid in a separation unit or inanother portion of the formation that is being heated. Cleaned orfiltered water may be produced along with subsequent cooling of theformation.

[2060] In an in situ conversion process embodiment, a hot formation maytreat water to remove dissolved cations (e.g., calcium and/or magnesiumions). The untreated water may be converted to steam in the formation.The steam may be produced and condensed to provide softened water (e.g.,water from which calcium and magnesium salts have been removed). Ifadditional water is provided to the formation, the retained salts in theformation may dissolve in the water and “hard” water may be produced.Therefore, order of treatment may be a factor in water purificationwithin a formation. A hot formation may sterilize introduced water bydestroying microbes.

[2061] In certain embodiments, a cooled formation may be used as a largeactivated carbon bed. After pyrolysis and/or synthesis gas generation atreated, cooled formation may be permeable and may include a significantweight percentage of char/coke. The formation may be substantiallyuniformly permeable without significant fluid passage fractures fromwellbore to wellbore within the formation. Contaminated water may beprovided to the cooled formation. The water may pass through the cooledformation to a production well. Material (e.g., hydrocarbons or metalcations) may be adsorbed onto carbon in the cooled formation, therebycleaning the water. In some embodiments, the formation may be used as afilter to remove microbes from the provided water. The filtrationcapability of the formation may depend upon the pore size distributionof the formation.

[2062] A treated portion of formation may be used trap and filter outparticulates. Water with particulates may be introduced into a firstwellbore. Water may be produced from production wells. When theparticulate matter clogs the pore space adjacent to the first wellboresufficiently to inhibit further introduction of water with particulates,the water with particulates may be introduced into a different wellbore.A large number of wellbores in a formation subject to in situ treatmentmay provide an opportunity to purify a large volume of water and/orstore a large amount of particulate matter in a formation.

[2063] Water quality may be improved using a heated formation. Forexample, after pyrolysis (and/or synthesis gas generation) is completed,formation water that was inhibited from passing into the formationduring conversion by freeze wells or other types of barriers may beallowed to pass through the spent formation. The formation water may bepassed through a hot formation to form steam and soften the water (i.e.,ionic compounds are not present in significant amounts in the producedsteam). The steam produced from the formation may be condensed to formformation water. The formation water may be passed through a carbon bed(in a surface facility or in a cooled, spent portion of the formation)to treat the formation water by adsorption, absorption, and/orfiltering.

[2064]FIG. 344 illustrates an embodiment for sequestering carbon dioxideas carbonate compounds in a portion of a formation. The carbon dioxidemay be sequestered in the formation by forming carbonate compounds fromthe carbon dioxide through carbonation reactions with pore water. Energyinput into heat sources 8537 may be used to control a temperature of theheated portion of formation 8540. Valves may be used to control apressure of the heated portion of the formation. In other embodiments,carbon dioxide may be sequestered in a cooled formation by adsorbing thecarbon dioxide on carbon than remains in the formation.

[2065] In the embodiment depicted in FIG. 344, solution 8538 is providedto the lower portion of the formation through well 8541 into dippingformation 8540. The solution may be obtained, for example, from naturalgroundwater flow or from an aquifer in a deeper formation. In anembodiment, the solution may be seawater. In some embodiments, the saltcontent of the water may be concentrated by evaporation. In certainembodiments, the solution may be obtained from man-made industrialsolutions (e.g., slaked lime solution) or agricultural runoff. Thesolution may include sodium, magnesium, calcium, iron, manganese, and/orother dissolved ions. Furthermore, the solution may contact the ash fromthe spent formation as it is provided to the post treatment formation.Contact of the solution with the formation ash may produce a buffered,basic solution.

[2066] In some sequestration embodiments, carbon dioxide 8539 may beprovided to the upper portion of the formation through well 8542simultaneously with providing solution 8538 to the formation. Thesolution may be provided to the lower portion of the formation, suchthat the solution rises through a portion of the provided carbondioxide. Carbonate compounds may form in a dissolution zone at theinterface of the solution and the carbon dioxide. In certainembodiments, the carbonate compounds may form by the reaction of thebasic solution with the carbonic acid produced when the carbon dioxidedissolves in the solution. Other mechanisms, however, may also cause theformation and precipitation of the carbonate compounds.

[2067] The type of carbonate compounds formed may be determined by thedissolved ions in the solution. Examples of carbonate compounds include,but are not limited to, calcite (CaCO₃), magnesite (MgCO₃), siderite(FeCO₃), rhodochrosite (MnCO₃), ankerite (CaFe(CO₃)₂), dolomite(CaMg(CO₃)₂), ferroan dolomite, magnesium ankerite, nahcolite (NaHCO₃),dawsonite (NaAl(OH)₂CO₃), and/or mixtures thereof. Other carbonatecompounds that may be precipitated include, but are not limited to,cerussite (PbCO₃), malachite (Cu₂(OH)₂CO₃, azurite (Cu₃(OH)₂(CO₃)₂),smithsonite (ZnCO₃), witherite (BaCO₃), strontianite (SrCO₃), and/ormixtures thereof.

[2068] A portion of the solution may be slowly withdrawn from theformation to deposit carbonate compounds within the formation. Afterwithdrawal, the solution may be reinserted into the formation tocontinue precipitation of carbonate compounds in the formation. Thesolution may rise again through the provided carbon dioxide andadditional carbonates may be formed and precipitated. The solution maybe cycled up and down within the formation to maximize the precipitationof carbonates within the formation. The carbonate compounds may remainwithin the formation.

[2069] In an embodiment, chemical compounds (e.g., CaO) may be added tothe solution if the amount of ash remaining in the formation isinsufficient to provide adequate buffering. In some embodiments,chemical compounds may be added to surface water to produce a solution.

[2070] Altering the pH of a solution in which carbon dioxide isdissolved may allow carbonate formation. Compounds that hydrolyze indifferent temperature ranges to produce basic compounds may be includedin the solution. Therefore, altering the solution temperature may alterthe solution pH, thus allowing carbonate formation. Compounds thathydrolyze to produce basic compounds may include cyanates and nitrites.Examples of cyanates and nitrites may include, but are not limited to,potassium cyanate, sodium cyanate, sodium nitrite, potassium nitrite,and/or calcium nitrite. In some embodiments, urea may also hydrolyze toproduce a basic compound.

[2071] In a sequestration embodiment, carbon dioxide may be allowed todiffuse throughout a solution within a formation. The solution mayinclude at least one of the compounds that hydrolyze. The formation maybe heated such that the compound(s) included in the solution hydrolyzesand produces a basic solution. The carbonate compounds may precipitatewhen appropriate ions (e.g., calcium and/or magnesium) are present.Altering the solution temperature may provide an ability to alter theoccurrence and rate of carbonate precipitation in the formation. Heatmay be provided from heat sources in the formation.

[2072] In a sequestration embodiment, carbon dioxide may be provided toa dipping formation. A solution may be provided to the dipping formationso that the solution contacts carbon dioxide to allow for precipitationof carbonate in the formation. Carbon dioxide and/or solution additionmay be cycled to increase the amount of carbonate formed in theformation.

[2073] Formation of carbonate compounds may inhibit movement of mobileor released hydrocarbon compounds to groundwater. Formation of carbonatecompounds may decrease the permeability of the formation and inhibitwater or other fluid from migrating into or out of a portion of theformation in which carbonates have been formed. Formation of carbonatesmay decrease leaching of metals in the formation to groundwater,decrease formation deformation, and/or decrease well damage by providingsupport for the remaining formation overburden. In certain in situconversion process embodiments, the formation of carbonate compounds maybe a part of the abandonment and reclamation process for the formation.

[2074] In an embodiment, heating during in situ conversion processes maycause decomposition of calcite (limestone) or dolomite to lime andmagnesite. Upon carbonation, the calcite and dolomite may bereconstituted. The reconstitution may result in sequestration of asignificant volume of carbon dioxide.

[2075] In a sequestration embodiment, existing wellbores may be usedduring formation of carbonates in the formation. A solution may beprovided to the formation and recovery of the solution may be providedfrom adjacent or closely spaced wells to create small circulation cells.In some embodiments with a dipping or thick formation, a counterflow ofcarbon dioxide and water may be applied. The carbon dioxide may beprovided downdip (e.g., a point lower in the formation) and the solutionprovided updip (e.g., a point higher in the formation). The carbondioxide and the solution may migrate past each other in a counterflowmanner. In other embodiments, the carbon dioxide may be bubbled upthrough a solution-filled formation.

[2076] In a sequestration embodiment, precipitation of mineral phases(e.g., carbonates) may cement together the friable and unconsolidatedformation matrix remaining after an in situ conversion process. Incertain embodiments, the formation of minerals in an in situ formationmay be similar to natural mineral formation and cementation, thoughsignificantly accelerated.

[2077] In an embodiment, vertical and/or horizontal mineral formationnear a well may provide at least some well integrity. Mineralprecipitation may provide the formation around the well with highercohesiveness and strength. The increased cohesiveness and strength mayinhibit compaction and deformation of the formation around the wellbore.

[2078] In some in situ conversion process embodiments, non-hydrocarbonmaterials such as minerals, metals, and other economically viablematerials contained within the formation may be economically producedfrom the formation. In some embodiments, the non-hydrocarbon materialsmay be mined or extracted from the formation following an in situconversion process. However, mining or extracting material following anin situ conversion process may not be economically or environmentallyfavorable. In certain embodiments, non-hydrocarbon materials may berecovered and/or produced prior to, during, and/or after the in situconversion process for treating hydrocarbons using an additional in situprocess of treating the formation for producing the non-hydrocarbonmaterials.

[2079] In an embodiment for producing non-hydrocarbon material, aportion of the formation may be subjected to in situ conversion processto produce hydrocarbons and/or synthesis gas from the formation. Thetemperature of the portion may be reduced below the boiling point ofwater at formation conditions. A first fluid may be injected into theportion. The first fluid may be injected through a production well,heater well, or injection well. The first fluid may include an agentthat reduces, mixes, combines, or forms a solution with non-hydrocarbonmaterials to be recovered. The first fluid may be water, a basicsolution, an acid solution, and/or a hydrocarbon fluid. In someembodiments, the first fluid may be introduced into the formation as ahot or warm liquid. The first fluid may be heated using heat-generatedin another portion of the formation and/or using excess heat fromanother portion of the formation.

[2080] A second fluid may be produced in the formation from formationmaterial and the first fluid. The second fluid may be produced from theformation through production wells. The second fluid may include desirednon-hydrocarbon materials from the formation. The non-hydrocarbonmaterials may include valuable metals such as, but not limited to,aluminum, nickel, vanadium, and gold. The non-hydrocarbon materials mayalso include minerals that contain phosphorus, sodium, or magnesium. Incertain embodiments, the second fluid may include metals combined withminerals. For example, the second fluid may contain phosphates,carbonates, etc. Metals, minerals, or other non-hydrocarbon materialscontained within the second fluid may be produced or extracted from thesecond fluid.

[2081] Producing the non-hydrocarbon materials may include separatingthe materials from the solution mixture. Producing the non-hydrocarbonmaterials may include processing the second fluid in a surface facilityor refinery. In some embodiments, the first fluid may be circulatedthrough the formation from an injection well to a removal site of thesecond fluid. Any portion of the first fluid remaining in the secondfluid may be recirculated (or re-injected) into the formation as aportion of the first fluid. In other embodiments, the second fluid maybe treated at the surface to remove non-hydrocarbon materials from thesecond fluid. This may reconstitute the first fluid from the secondfluid. The reconstituted first fluid may be re-injected into theformation for further material recovery.

[2082] In some embodiments, non-hydrocarbon materials may be producedfrom a formation prior to treating the formation in situ. Heat may beprovided to the formation from heat sources. The formation may reach anaverage temperature approaching below pyrolysis temperatures (e.g.,about 260° C. or less). A first fluid may be injected into theformation. The first fluid may dissolve and or entrain formationmaterial to form a second fluid. The second fluid may be produced fromthe formation.

[2083] Some relatively permeable formations may include nahcolite,trona, and/or dawsonite within the formation. For example, nahcolite maybe contained in unleached portions of a formation. Unleached portions ofa formation are parts of the formation where groundwater has not leachedout minerals within the formation.

[2084] Nahcolite is a mineral that includes sodium bicarbonate (NaHCO₃).Greater than about 5 weight %, and in some embodiments even greater thanabout 10 weight %, or greater than about 20 weight % nahcolite may bepresent in a formation. Dawsonite is a mineral that includes sodiumaluminum carbonate (NaAl(CO₃)(OH)₂). Dawsonite may be present in aformation at weight percents greater than about 2 weight % or, in someembodiments, greater than about 5 weight %. The nahcolite and/ordawsonite may dissociate at temperatures used in an in situ conversionprocess of treating a formation. The dissociation is stronglyendothermic and may produce large amounts of carbon dioxide. Thenahcolite and/or dawsonite may be solution mined prior to, during,and/or following treating a formation in situ to avoid the dissociationreactions. For example, hot water may be used to form a solution withnahcolite. Nahcolite may form sodium ions (Na⁺) and bicarbonate ions(HCO₃ ⁻) in aqueous solution. The solution may be produced from theformation through production wells.

[2085] A formation that includes nahcolite and/or dawsonite may betreated using an in situ conversion process. A perimeter barrier may beformed around the portion of the formation to be treated. The perimeterbarrier may inhibit migration of water into the treatment area. Duringan in situ conversion process, the perimeter barrier may inhibitmigration of dissolved minerals and formation fluid from the treatmentarea. During initial heating, a portion of the formation to be treatedmay be raised to a temperature below the disassociation temperature ofthe nahcolite. The first temperature may be less than about 90° C., orin some embodiments, less than about 80° C. The first temperature maybe, however, any temperature that increases a reaction of a solutionwith nahcolite, but is also below a temperature at which nahcolite maydissociate (above about 95° C. at atmospheric pressure). A first fluidmay be injected into the heated portion. The first fluid may includewater, steam, or other fluids that may form a solution with nahcoliteand/or dawsonite. The first fluid may be at an increased temperature(e.g., about 90° C. or about 100° C.). The increased temperature may besubstantially similar to the first temperature of the portion of theformation.

[2086] In some embodiments, the portion of the formation may be atambient temperature and the first fluid may be injected at an increasedtemperature. The increased temperature may be a temperature below aboiling point of the first fluid (e.g., about 90° C. for water).Providing the first fluid at an increased temperature may increase atemperature of a portion of the formation. Additional heat may beprovided from one or more heat sources (e.g., a heater in a heater well)placed in the formation.

[2087] In other embodiments, steam is included in the first fluid. Heatfrom the injection of steam into the formation may be used to provideheat to the formation. The steam may be produced from recovered heatfrom the formation (e.g., from steam recovered during remediation of aportion) or from heat exchange with formation fluids and/or with surfacefacilities.

[2088] A second fluid may be produced from the formation followinginjection of the first fluid into the formation. The second fluid mayinclude products of injection of the first fluid into the formation. Forexample, the second fluid may include carbonic acid or other hydratedcarbonate compounds formed from the dissolution of nahcolite in thefirst fluid. The second fluid may also include minerals and/or metals.The minerals and/or metals may include sodium, aluminum, phosphorus, andother elements. Producing the second fluid from the formation may reducean amount of carbon dioxide produced from the formation during an insitu conversion process. Reducing the amount of carbon dioxide may beadvantageous because the production of carbon dioxide from nahcolite isendothermic and uses significant amounts of energy. For example,nahcolite has a heat of decomposition of about 0.66 joules per kilogram(J/kg). The energy required to pyrolyze hydrocarbons in a formationusing an in situ process may generally be about 0.35 J/kg. Thus, todecompose nahcolite from a formation having about 20 weight % nahcolite,about 0.13 J/kg additional energy would be needed. Removing nahcolitefrom a formation using a solution mining process prior to treating theformation using an in situ conversion process may significantly reducecarbon dioxide emissions from the formation as well as energy requiredto heat the formation.

[2089] Some minerals (e.g., trona, pirssonite, or gaylussite) mayinclude associated water. Solution mining, or removing, such mineralsbefore heating the formation may reduce costs of heating the formationto pyrolysis temperatures since associated water is removed prior toheating of the formation. Thus, the heat for dissociation of water fromthe mineral does not have to be provided to the formation.

[2090]FIG. 345 depicts an embodiment for solution miing a formation.Barrier 6500 (e.g., a frozen barrier) may be formed around acircumference of treatment area 6510 of the formation. Barrier 6500 maybe any barrier formed to inhibit a flow of water into or out oftreatment area 6510. For example, barrier 6500 may include one or morefreeze wells that inhibit a flow of water through the barrier. In someembodiments, barrier 6500 has a diameter of about 18 m. Barrier 6500 maybe formed using one or more barrier wells 6502. Barrier wells 6502 mayhave a spacing of about 2.4 m. Formation of barrier 6500 may bemonitored using monitor wells 6504 and/or by monitoring devices placedin barrier wells 6502.

[2091] Water inside treatment area 6510 may be pumped out of thetreatment area through production well 6516. Water may be pumped until aproduction rate of water is low. Heat may be provided to treatment area6510 through heater wells 6514. The provided heat may heat treatmentarea 6510 to a temperature of about 90° C. or, in some embodiments, to atemperature of about 100° C., 110° C., or 120° C. A temperature oftreatment area 6510 may be monitored using temperature measurementdevices placed in temperature wells 6518.

[2092] A first fluid (e.g., water) may be injected through one or moreinjection wells 6512. The first fluid may also be injected through aheater or production well located in the formation. The first fluid maymix and/or combine with non-hydrocarbon materials (e.g., minerals,metals, nahcolite, and dawsonite) that are soluble in the first fluid toproduce a second fluid. The second fluid, containing the non-hydrocarbonmaterials, may be removed from the treatment area through productionwell 6516 and/or heater wells 6514. Production well 6516 and heaterwells 6514 may be heated during removal of the second fluid. Afterproducing a majority of the non-hydrocarbon materials from treatmentarea 6510, solution remaining within the treatment area may be removed(e.g., by pumping) from the treatment area through production well 6516and/or heater wells 6514. A relatively high permeability treatment area6510 may be produced following removal of the non-hydrocarbon materialsfrom the treatment area.

[2093] Hydrocarbons within treatment area 6510 may be pyrolyzed and/orproduced using an in situ conversion process of treating a formationfollowing removal of the non-hydrocarbon materials. Heat may be providedto treatment area 6510 through heater wells 6514. A mixture ofhydrocarbons may be produced from the formation through production well6516 and/or heater wells 6514.

[2094] In certain embodiments, during an initial heating up to atemperature near a boiling temperature of water, unleached solubleminerals within the formation may be disaggregated and dissolved inwater condensing within the formation. The water may be condensing incooler portions of the formation. Some of these minerals may flow in thecondensed water to production wells. The water and minerals are producedthrough the production wells.

[2095] Following an in situ conversion process, treatment area 6510 maybe cooled during heat recovery by introduction of water to produce steamfrom a hot portion of the formation. Introduction of water to producesteam may vaporize some hydrocarbons remaining in the formation. Watermay be injected through injection wells 6512. The injected water maycool the formation. The remaining hydrocarbons and generated steam maybe produced through production wells 6516 and/or heater wells 6514.Treatment area 6510 may be cooled to a temperature near the boilingpoint of water.

[2096] Treatment area 6510 may be further cooled to a temperature atwhich water will begin to condense within the formation (i.e., atemperature below a boiling temperature of water). Removing the water orother solvents from treatment area 6510 may also remove any materialsremaining in the treatment area that are soluble in water. The water maybe pumped out of treatment area 6510 through production well 6516 and/orheater wells 6514. Additional water and/or other solvents may beinjected into treatment area 6510. This injection and removal of watermay be repeated until a sufficient water quality within treatment area6510 is reached. Water quality may be measured at injection wells 6512,heater wells 6514, and/or production wells 6516. The sufficient waterquality may be a water quality that substantially matches a waterquality of treatment area 6510 prior to treatment.

[2097] In some embodiments, treatment area 6510 may include a leachedzone located above an unleached zone. The leached zone may have beenleached naturally and/or by a separate leaching process. In certainembodiments, the unleashed zone may be at a depth of about 500 m. Athickness of the unleached zone may be about 100 m to about 500 m.However, the depth and thickness of the unleached zone may varydepending on, for example, a location of treatment area 6510 and a typeof formation. A first fluid may be injected into the unleached zonebelow the leached zone. Heat may also be provided into the unleachedzone.

[2098] In certain embodiments, a section of a formation may be leftunleached or without injection of a solution. The unleached section maybe proximate a selected section of the formation that has been leachedby providing a first fluid as described above. The unleached section mayinhibit the flow of water into the selected section. In someembodiments, more than one unleached section may be proximate a selectedsection.

[2099] Water may be injected into the formation through a heater well oran injection well. The water may be heated and/or injected as steam. Thewater may be injected at a temperature at or near the decompositiontemperature of nahcolite. For example, the water may be at a temperatureof about 70° C., 90° C., 100° C., or 110° C. Nahcolite within theformation may form an aqueous solution following the injection of water.The aqueous solution may be removed from the formation through a heaterwell, injection well, or production well. Removing the nahcolite removesmaterial that would otherwise form carbon dioxide during heating of theformation to pyrolysis temperature. Removing the nahcolite may alsoinhibit the endothermic dissociation of nahcolite during an in situconversion process. Removing the nahcolite may reduce mass within theformation and increase a permeability of the formation. Reducing themass within the formation may reduce the heat required to heat totemperatures needed for the in situ conversion process. Reducing themass within the formation may also increase a speed at which a heatfront within the formation moves. Increasing the speed of the heat frontmay reduce a time needed for production to begin. In some embodiments,slightly higher temperatures may be used in the formation (e.g., aboveabout 120° C.) and the nahcolite may begin to decompose. In such a case,nahcolite may be removed from the formation as a soda ash (Na₂CO₃).

[2100] Nahcolite removed from the formation may be heated in a surfacefacility to form sodium carbonate and/or sodium carbonate brine. Heatingnahcolite will form sodium carbonate according to the equation:

2NaHCO₃→Na₂CO₃+CO₂+H₂O.  (43)

[2101] The sodium carbonate brine may be used to solution mine alumina.The carbon dioxide produced may be used to precipitate alumina. If sodaash is produced from solution mining of nahcolite, the soda ash may betransported to a separate facility for treatment. The soda ash may betransported through a pipeline to the separate facility.

[2102] Following removal of nahcolite from the formation, the formationmay be treated using an in situ conversion process to producehydrocarbon fluids from the formation. Remaining water is drained fromthe solution mining area through dewatering wells prior to heating to insitu conversion process temperatures. During the in situ conversionprocess, a portion of the dawsonite within the formation may decompose.Dawsonite will typically decompose at temperatures above about 270° C.according to the reaction:

2NaAl(OH)₂CO₃→Na₂CO₃+Al₂O₃+2H₂O+CO₂.  (44)

[2103] The alumina formed from EQN. 44 will tend to be in the form ofchi alumina. Chi alumina is relatively soluble in basic fluids.

[2104] Alumina within the formation may be solution mined using arelatively basic fluid following reaching pyrolysis temperatures ofhydrocarbons within the formation. For example, a dilute sodiumcarbonate brine, such as 0.5 Normal Na₂CO₃, may be used to solution minealumina The sodium carbonate brine may be obtained from solution miningthe nahcolite. Obtaining the basic fluid by solution mining thenahcolite may significantly reduce costs associated with obtaining thebasic fluid. The basic fluid may be injected into the formation througha heater well and/or an injection well. The basic fluid may form analumina solution that may be removed from the formation. The aluminasolution may be removed through a heater well, injection well, orproduction well. An excess of basic fluid may have to be maintainedthroughout an alumina solution mining process.

[2105] Alumina may be extracted from the alumina solution in a surfacefacility. In an embodiment, carbon dioxide may be bubbled through thealumina solution to precipitate the alumina from the basic fluid. Carbondioxide may be obtained from the in situ conversion process or fromdecomposition of the dawsonite during the in situ conversion process.

[2106] In certain embodiments, a formation may include portions that aresignificantly rich in either nahcolite or dawsonite only. For example, aformation may contain significant amounts of nahcolite (e.g., greaterthan about 20 weight %) in a depocenter of the formation. The depocentermay contain only about 5 weight % or less dawsonite on average. However,in bottom layers of the formation, a weight percent of dawsonite may beabout 10 weight % or even as high as about 25 weight %. In suchformations, it may be advantageous to solution mine for nahcolite onlyin nahcolite-rich areas, such as the depocenter, and solution mine fordawsonite only in the dawsonite-rich areas, such as the bottom layers.This selective solution mining may significantly reduce a fluid cost,heating cost, and/or equipment cost associated with operating a solutionmining process.

[2107] Nordstrandite (Al(OH)₃) is another aluminum bearing mineral thatmay be found in a formation. Nordstrandite decomposes at about the sametemperatures (about 300° C.) as dawsonite and will produce aluminaaccording to the equation:

2Al(OH)₃→Al₂O₃+3H₂O.  (45)

[2108] Nordstrandite is typically found in formations that also containdawsonite and may be solution mined simultaneously with the dawsonite.

[2109] Solution mining dawsonite and nahcolite may be a simple processthat produces only aluminum and soda ash from a formation. It may bepossible to use some or all hydrocarbons produced from an in situconversion process to produce direct current (DC) electricity on a siteof the formation. The produced DC electricity may be used on the site toproduce aluminum metal from the alumina using the Hall process. Aluminummetal may be produced from the alumina by melting the alumina in asurface facility on the site. Generating the DC electricity at the sitemay save on costs associated with using hydrotreaters, pipelines, orother surface facilities associated with transporting and/or treatinghydrocarbons produced from the formation using the in situ conversionprocess.

[2110] Some formations may also contain amounts of trona. Trona is asodium sesquicarbonate (Na₂CO₃.NaHCO₃.2H₂O) that has properties andundergoes reactions (including decomposition) very similar to those ofnahcolite. Treatments for solution mining of trona may be substantiallysimilar to treatments used for solution mining of nahcolite.

[2111] For certain types of formations, solution mining may be used torecover non-hydrocarbon materials prior to heating the formation tohydrocarbon pyrolysis temperatures. Other non-hydrocarbon materials thatmay be solution mined include carbonates (e.g., trona, eitelite,burbankite, shortite, pirssonite, gaylussite, norsethite,thermonatrite), phosphates, carbonate-phosphates (e.g., bradleyite),carbonate chlorides (e.g., northupite), silicates (e.g., albite,analcite, sepiolite, loughlinite, labuntsovite, acmite, elpidite,magnesioriebeckite, feldspar), borosilicates (e.g., reedmergnerite,searlesite, leucosphenite), and halides (e.g., neighborite, cryolite,halite). Solution mining prior to hydrocarbon pyrolysis may increase apermeability of the formation and/or improve other features (e.g.,porosity) of the formation for the in situ process. Solution mining mayalso remove significant portions of compounds that will tend toendothermically dissociate at increased temperatures. Removing theseendothermically dissociating compounds from the formation tends todecrease an amount of heat input required to heat the formation.

[2112] For some types of formations, it may be advantageous to solutionmine a formation after pyrolysis and/or synthesis gas production. Manydifferent types of non-hydrocarbon materials may be removed from aformation following an in situ conversion process.

[2113] Metals may be found in certain bitumen deposits. For example,bitumen deposits may contain amounts of vanadium, nickel, uranium,platinum, or gold.

[2114] In certain embodiments a soluble compound (e.g., phosphates,bicarbonates, alumina, metals, minerals, etc.) may be produced from asoluble compound containing formation (e.g., a formation that containsnahcolite, dawsonite, nordstrandite, trona, carbonates,carbonate-phosphates, carbonate chlorides, silicates, borosililcates,etc.) that is different from a relatively permeable formation. Forexample, the soluble compound containing formation may be adjacent(lower or higher) than the relatively permeable formation, or atdifferent non-adjacent depths than the relatively permeable formation.In other embodiments, the soluble compound containing formation may belocated at a different geographic location than the relatively permeableformation.

[2115] In an embodiment, heat is provided from one or more heat sourcesto at least a portion of a relatively permeable formation. A mixture, atsome point, may be produced from the formation. The mixture may includehydrocarbons from the formation as well as other compounds such as CO₂,H₂, etc. Heat from the formation, or heat from the mixture produced fromthe formation, may be used to adjust or change a quality of a firstfluid that is provided to the soluble compound containing formation.Heat may be provided in the form of hot water or steam produced from theformation. In other embodiments, heat may be transferred by heatexchangers to the first fluid. In other embodiments, a heated portion orcomponent from the mixture may be mixed with the first fluid to heat thefluid.

[2116] Alternately, or in addition, a component from the mixtureproduced from the relatively permeable formation may be used to adjust aquality of a first fluid. For example, acidic compounds (e.g., carbonicacid, organic acids) or basic compounds (e.g., ammonium, carbonate, orhydroxide compounds) from the mixture produced from the relativelypermeable formation may be used to adjust the pH of the first fluid. Forexample, CO₂ from the relatively permeable formation may be used withwater to acidify the first fluid. In certain embodiments, componentsadded to the first fluid (e.g., divalent cations, pyridines, or organicacids such as carboxylic acids or naphthenic acids) may increase thesolubility of the soluble compound in the first fluid.

[2117] Once adjusted (e.g., heated and/or changed by having at least onecomponent added to the first fluid), the first fluid may be injectedinto the soluble compound containing formation. The first fluid may, insome embodiments, include hot water or steam. The first fluid mayinteract with the soluble compound. The soluble compound may at leastpartially dissolve. A second fluid including the soluble compound may beproduced from the soluble compound containing formation. The solublecompound may be separated from the second fluid stream and treated orprocessed. Portions of the second fluid may be recycled into theformation.

[2118] In certain embodiments, heat from the relatively permeableformation may migrate and heat at least a portion of the solublecompound containing formation. In some embodiments, the soluble compoundcontaining formation may be substantially near, adjacent to, orintermixed with the relatively permeable formation. The heat thatmigrates may be useful to enhance the solubility of the soluble compoundwhen the first fluid is applied to the soluble compound containingformation. Heat that migrates from the relatively permeable formationmay be recovered instead of being lost.

[2119] Reusing openings (wellbores) for different applications may becost effective in certain embodiments. In some embodiments, openingsused for providing the heat sources (or from producing from therelatively permeable formation) may be used to provide the first fluidto the soluble compound containing formation or to produce the secondfluid from the soluble compound containing formation.

[2120] In certain embodiments, a solution may be first provided to, orproduced from, a formation in a solution mining operation. The solutionmay be provided or produced through openings. One or more of the sameopenings may later be used as heater wells or producer wells for an insitu conversion process. Additionally, one or more of the same openingsmay be used again for providing a first fluid to the same formationlayer or to a different formation layer. For example, the openings maybe used to solution mine components such as nahcolite. These openingsmay further be used as heater wells or producer wells in the relativelypermeable formation. Then the openings may be used to provide the firstfluid to either the hydrocarbon containing layer or a different layer ata different depth than the hydrocarbon containing layer. These openingsmay also be used when producing second fluid from the solution compoundcontaining formation.

[2121] Relatively permeable formations may have varied geometries andshapes. Conventional extraction techniques may not be appropriate forall formations. In some formations, rich hydrocarbon containing materialmay be positioned in layers that are too thin to be economicallyextracted using conventional methods. The rich relatively permeableformations typically occur in beds having thicknesses between about 0.2m and about 8 m.

[2122]FIGS. 308 and 309 depict representations of embodiments of in situconversion process systems that may be used to produce a thin richhydrocarbon layer. To produce such layers, directionally drilled wellsmay be used to heat the thin hydrocarbon layer within the formation,plus a minimum amount of rock above and/or below. In some embodiments,the heat source wells may be placed in the rock above and/or below thethin hydrocarbon layer. The wells may be closely spaced to reduce heatlosses and speed the heating process. In addition, drilling technologiessuch as geosteering, slim well, coiled tubing, and other techniques maybe utilized to accurately and economically place the wells. Conductiveheat losses to the surrounding formation may be offset by a high oilcontent of the thin hydrocarbon layer, rapid heating of the thinhydrocarbon layer (e.g., a heating rate in the range of about 1° C./dayto about 15° C./day), and/or close spacing (meter scale) of heaters.Subsidence may be reduced, or even minimized, by positioning heaterwells in a non-hydrocarbon and/or lean section of the formationimmediately beneath and/or at the base of the thin hydrocarbon layer. Anon-hydrocarbon and/or lean section of the formation may lose lessmaterial than the thin hydrocarbon layer. Therefore, the structuralintegrity of formation may be maintained.

[2123] In some in situ conversion process embodiments, formations may betreated in situ by heating with a heat transfer fluid. A method fortreating a formation may include injecting a heat transfer fluid intothe formation. In some embodiments, steam may be used as the heattransfer fluid. The heat from the heat transfer fluid may transfer to aselected section of the formation. In conjunction with heat from heatsources, the heat may pyrolyze at least some of the hydrocarbons withinthe selected section of the formation. A vapor mixture that includespyrolysis products may be produced from the formation. The pyrolysisproducts may include hydrocarbons having an average API gravity of atleast about 25°. The vapor mixture may also include steam.

[2124] In one embodiment, hydrocarbons may be distilled from theformation. For example, hydrocarbons may be separated from the formationby steam distillation. The heat from the heat transfer fluid (e.g.,steam), and/or heat from heat sources, may vaporize some of thehydrocarbons within the selected section of the formation. The vaporizedhydrocarbons may include hydrocarbons having a carbon number greaterthan about 1 and a carbon number less than about 8. The vapor mixturemay include the vaporized hydrocarbons. For example, in a relativelypermeable formation, pyrolyzation fluids and steam may distill asubstantial portion of unconverted heavy hydrocarbons. In addition,coke, sulfur, nitrogen, oxygen, and/or metals may be separated fromformation fluid in the formation.

[2125] It may be advantageous to use steam injection for in situtreatment of heavy hydrocarbon or bitumen containing formations. In anembodiment, steam injection and soaking with steam may be applied torelatively permeable formations that have sufficiently high permeabilityand homogeneity. Substantially uniform heating of a substantial portionof the hydrocarbons in a formation to pyrolysis temperatures with heattransfer from steam and heat sources (e.g., electric heaters, gasburners, natural distributed combustors, etc.) may be enhanced if theformation has relatively high permeability and homogeneity. Relativelyhigh permeability and homogeneity may allow the injected steam tocontact a large surface area within the formation.

[2126] In certain embodiments, in situ treatment of hydrocarbons may beaccomplished with a suitable combination of steam pressure, temperature,and residence time of injected steam, together with a selected amount ofheat from heat sources, at a selected depth in the formation. Forexample, at a temperature of about 350° C., at hydrostatic pressure, andat a depth of about 700 m to about 1000 m, a residence time of at leastapproximately one month may be required for in situ steam treatment ofhydrocarbons with steam and heat sources.

[2127] In some embodiments, relatively deep formations may beparticularly suitable for in situ treatment with heat sources and steaminjection. Higher steam pressures and temperatures may be readilymaintained in relatively deep formations. Furthermore, steam may be ator approaching supercritical conditions below a particular depth.Supercritical steam or near supercritical steam may facilitatepyrolyzation of hydrocarbons. In other embodiments, in situ treatment ofa relatively shallow formation may be performed with a sufficient amountof overpressure (e.g., an overpressure above a hydrostatic pressure).The amount of overpressure may depend on the strength of the formationor the overburden of the formation.

[2128] In an embodiment, in situ treatment of a formation may includeheating a selected section of the formation with one or more heatsources, and one or more cycles of steam injection. The cycles of steammay soak the formation with steam for a selected time period. Theselected time period may be about one month. In other embodiments, theselected time period may be about one month to about six months. Theselected section may be heated to a temperature between about 275° C.and about 350° C. In another embodiment, the formation may be heated toa temperature of about 350° C. to about 400° C. A vapor mixture, whichmay include pyrolyzation fluids, may be produced from the formationthrough one or more production wells placed in the formation.

[2129] In certain embodiments, in situ treatment of a formation mayinclude continuous steam injection into the formation, together withaddition of heat from heat sources. Pyrolyzation fluids may be producedfrom different portions of the formation during such treatment.

[2130]FIG. 347 illustrates a schematic of an embodiment of continuousproduction of a vapor mixture from a formation. FIG. 347 includesformation 8262 with heat transfer fluid injection well 8264 and well8266. The wells may be members of a larger pattern of wells placedthroughout the formation. A portion of a formation may be heated topyrolyzation temperatures by heating the formation with heat sources andan injected heat transfer fluid. Heat transfer fluid 8268, such assteam, may be injected through injection well 8264. Other wells may beused to provide the steam. Injected heat transfer fluid may be at atemperature between about 300° C. and about 500° C. In an embodiment,heat transfer fluid 8268 is steam.

[2131] Heat transfer fluid 8268, and heating from the heat sources, mayheat region 8263 of the formation between wells 8264 and 8266. Suchheating may heat region 8263 into a selected temperature range (e.g.,between about 275° C. and about 400° C.). An advantage of a continuousproduction method may be that the temperature across region 8263 may besubstantially uniform and substantially constant with time once theformation has reached substantial thermal equilibrium. Vapor mixture8270 may exit continuously through well 8266. Vapor mixture 8270 mayinclude pyrolysis fluids and/or steam. In one embodiment, vapor mixture8270 may be fed to surface separation unit 8272. Separation unit 8272may separate vapor mixture 8270 into stream 8274 and hydrocarbons 8276.Stream 8274 may be composed primarily of steam or water. Stream 8274 maybe re-injected into the formation. Hydrocarbons may include pyrolysisfluids and hydrocarbons distilled from the formation.

[2132] In an embodiment, production of a vapor mixture from a formationmay be performed in a batch mode. Injection of the heat transfer fluidmay continue for a period of time, together with heat from one or moreheat sources. In an embodiment, heat from the heat sources may combinewith heat from transfer fluid until the temperature of a portion of theformation is at a desired temperature (e.g., between about 275° C. andabout 400° C.). Higher or lower temperatures may also be used.Alternatively, injection may continue until a pore volume of the portionof the formation is substantially filled. After a selected period oftime subsequent to ceasing injection of the heat transfer fluid, vapormixture 8270 may be produced from the formation through wellbore 8266.The vapor mixture may include pyrolysis fluids and/or steam. In someembodiments, the vapor mixture may exit through wellbore 8264. In anembodiment, the selected period of time may be about one month.

[2133] Injected steam may contact a substantial portion of a volume ofthe formation to be treated. The heat transfer fluid may be injectedthrough one or more injection wells. Similarly, the heat sources may beplaced in one or more heater wells. The injection wells may be locatedsubstantially horizontally in the formation. Alternatively, theinjection wells may be disposed substantially vertically or any desiredangle (e.g., along dip of the formation). The heat transfer fluid may beinjected into regions of relatively high water saturation. Relativelyhigh water saturation may include water concentrations greater thanabout 50 volume percent. In some embodiments, the average spacingbetween injection wells may be between about 40 m and about 50 m. Inother embodiments, the average spacing may be between about 50 m andabout 60 m.

[2134] In an embodiment, the heat from injection of a heat transferfluid, together with heat from one or more heat sources, may pyrolyze atleast some of the hydrocarbons in the selected first section. In certainembodiments, the heat may mobilize at least some of the hydrocarbonswithin the selected first section. Injection of a heat transfer fluid,and/or heat from the heat sources, may decrease a viscosity ofhydrocarbons in the formation. Decreasing the viscosity of thehydrocarbons may allow the hydrocarbons to be more mobile. In addition,some of the heat may partially upgrade a portion of the hydrocarbons.Partial upgrading may reduce the viscosity and/or mobilize thehydrocarbons. Some of the mobilized hydrocarbons may flow (e.g., due togravity) from the selected first section of the formation to a selectedsecond section of the formation. Heat from the heat transfer fluid andthe heat sources may pyrolyze at least some of the mobilized fluids inthe selected second section.

[2135] In some embodiments, heat may be provided from one or more heatsources to at least one portion of the formation. The one or more heatsources may include electric heaters, flameless distributed combustors,or natural distributed combustors. Heat from the heat sources maytransfer to the selected first section and the selected second sectionof the formation. The heat may heat or superheat steam injected into theformation. The heat may also vaporize water in the formation to generatesteam. In addition, the heat from the heat sources may mobilize and/orpyrolyze hydrocarbons in the selected first section and/or the selectedsecond section of the formation.

[2136] In an embodiment, the selected first section and the selectedsecond section may be located in a relatively deep portion of theformation. For example, a relatively deep portion of a formation may bebetween about 100 m and about 300 m below the surface. Heat from theheat sources and the heat transfer fluid may pyrolyze at least some ofthe hydrocarbons within the selected second section of the formation. Insome embodiments, at least about 20 percent of the hydrocarbons in theformation may be pyrolyzed. The pyrolyzed hydrocarbons may have anaverage API gravity of at least about 25°.

[2137] In an embodiment, a vapor mixture may be produced from theformation. The vapor mixture may contain pyrolyzed fluids. In otherembodiments, the vapor mixture may contain pyrolyzed fluids and/or heattransfer fluid. The vapor mixture may include hydrocarbons distilledfrom the formation. The heat transfer fluid may be separated from thepyrolyzed fluids and distilled hydrocarbons at the surface of theformation. For example, heat transfer fluid may be separated using amembrane separation method. Alternatively, heat transfer fluid may beseparated from pyrolyzed fluids and distilled hydrocarbons in theformation. The pyrolyzed fluids and distilled hydrocarbons may then beproduced from the formation.

[2138] In an embodiment, the vapor mixture may be produced from theselected second section of the formation. Alternatively, the vapormixture may be produced from the selected first section.

[2139] In one embodiment, the mobilized fluids may be partially upgradedin the selected second section. The partially upgraded fluids may beproduced from the formation and re-injected back into the formation.

[2140] In certain embodiments, the vapor mixture may be produced throughone or more production wells. In some embodiments, at least some of thevapor mixture may be produced through a heat source wellbore.

[2141] In one embodiment, a liquid mixture composed primarily ofcondensed heat transfer fluid may accumulate in a portion of theformation. The liquid mixture may be produced from the formation. Theliquid mixture may include liquid hydrocarbons. The condensed heattransfer fluid may be separated from the liquid hydrocarbons in theformation and the condensed heat transfer fluid may be produced from theformation. Alternatively, the liquid mixture may be produced from theformation and fed to a separation unit. The separation unit may separatethe condensed heat transfer fluid from the liquid hydrocarbons. Theliquid hydrocarbons may then be re-injected into the formation.

[2142]FIG. 348 illustrates a cross-sectional representation of anembodiment of an in situ treatment process with steam injection. Portion8300 of the formation may be treated with steam injection. Portion 8301may be untreated. Horizontal injection and/or heat source wells 8302 maybe located in an upper or selected first section of portion 8300.Horizontal production wells 8304 may be located in a lower or selectedsecond section of portion 8300. The wells may be members of a largerpattern of wells placed throughout a portion of the formation.

[2143] Steam may be injected into the formation through wells 8302,and/or heat sources may be placed in such wells 8302 and provide heat tothe formation and/or to the steam. The heat from the steam and the heatsources may heat the selected first and second sections to pyrolyzationtemperatures and pyrolyze some of the hydrocarbons in the sections. Inaddition, heat from the steam injection and the heat sources maymobilize some hydrocarbons in the sections. The mobilized hydrocarbonsin the selected first section may flow (e.g., by gravity and or flowtowards low pressure of a pressure gradient established by productionwells) to the selected second section as indicated by arrows 8306. Someof the mobilized hydrocarbons may be pyrolyzed in the selected secondsection. Pyrolyzed fluids and/or mobilized fluids may be producedthrough production wells 8304. In an embodiment, condensed fluids (e.g.,condensed steam) may be produced through production wells in theselected second section.

[2144]FIG. 349 illustrates a cross-sectional representation of anembodiment of an in situ treatment process with steam injection and heatsources. Portion 8310 of the formation may be treated with heat fromheat sources and steam injection. Portion 8311 may be untreated. Portion8310 may include a horizontal heat source and/or injection well 8314located in an upper or selected first section. Horizontal productionwell 8312 may be located above the injection well in the selected firstsection of portion 8310. The production well and/or the injection wellmay include a heat source. Water and oil production well 8316 may beplaced in the selected second section of the formation. The wells may bemembers of a larger pattern of wells placed throughout a portion of theformation.

[2145] Heat and/or steam may be provided to the formation through well8314. Such heat and steam may heat the selected first and secondsections to pyrolyzation temperatures. *10 Hydrocarbons may be pyrolyzedin the selected first section between well 8312 and well 8314. Inaddition, the heat may mobilize some hydrocarbons in the sections. Themobilized hydrocarbons in the selected first section may flow throughregion 8319 to the selected second section as indicated by arrows 8318.Some of the mobilized hydrocarbons may be pyrolyzed in the selectedsecond section. Pyrolyzed fluids and/or mobilized fluids may be producedthrough production well 8312. In addition, condensed fluids (e.g.,steam) may be produced through production well 8316 in the selectedsecond section.

[2146] In one embodiment, a method of treating a relatively permeableformation in situ may include heating the formation with heat sources,and also injecting a heat transfer fluid into a formation and allowingthe heat transfer fluid to flow through the formation. Heat transferfluid may be injected into the formation through one or more injectionwells. The injection wells may be located substantially horizontally inthe formation. Alternatively, the injection wells may be disposedsubstantially vertically in the formation or at a desired angle. Thesize of a selected section of the formation may increase as a heattransfer fluid front migrates through the formation. “Heat transferfluid front” is a moving boundary between the portion of the formationtreated by heat transfer fluid and the portion untreated by heattransfer fluid. The selected section may be a portion of the formationtreated or contacted by the heat transfer fluid. Heat from the heattransfer fluid, together with heat from one or more heat sources, maypyrolyze at least some of the hydrocarbons within the selected sectionof the formation. In an embodiment, the average temperature of theselected section may be about 300° C., which corresponds to a heattransfer fluid pressure of about 90 bars.

[2147] In some embodiments, heat from the heat transfer fluid and/or oneor more heat sources may mobilize at least some of the hydrocarbons atthe heat transfer fluid front. The mobilized hydrocarbons may flowsubstantially parallel to the heat transfer fluid front. Heat from theheat transfer fluid, in conjunction with heat from the heat sources, maypyrolyze at least some of the hydrocarbons in the mobilized fluid.

[2148] In an embodiment, a vapor mixture may migrate to an upper portionof the formation. The vapor mixture may include pyrolysis fluids. Thevapor mixture may also include heat transfer fluid and/or distilledhydrocarbons. In an embodiment, the vapor mixture may be produced froman upper portion of the formation. The vapor mixture may be producedthrough one or more production wells located substantially horizontallyin the formation.

[2149] In one embodiment, a portion of the heat transfer fluid maycondense and flow to a lower portion of the selected section. A portionof the condensed heat transfer fluid may be produced from a lowerportion of the selected section. The condensed heat transfer fluid maybe produced through one or more production wells. Production wells maybe located substantially horizontally in the formation.

[2150]FIG. 350 illustrates a cross-sectional representation of anembodiment of an in situ treatment process with heat sources and steaminjection. Portion 8320 of the formation may be treated with heatsources and steam injection. Portion 8321 may be untreated. Portion 8320may include horizontal heat source and/or injection well 8326.Alternatively or in addition, portion 8320 may include vertical heatsource and/or injection well 8324. Horizontal production well 8328 maybe located in an upper portion of the formation. Portion 8320 may alsoinclude condensed fluid production well 8330 (production well 8330 maycontain one or more heat sources). The wells may be members of a largerpattern of wells placed throughout a portion of the formation.

[2151] Heat and/or steam may be provided into the formation throughwells 8326 or 8324. The heat and/or steam may flow through the formationin the direction indicated by arrows 8332. A size of a section treatedby the heat and/or steam (i.e., a selected section) increases as theheat and/or steam flows through the untreated portion of the formation.The formation may include migrating heat and/or steam front 8339 at aboundary between portion 8320 and portion 8321.

[2152] Mobilized fluids may flow in the direction of arrows 8334 towardproduction well 8328. Fluids may be pyrolyzed and produced throughproduction well 8328. Steam and distilled hydrocarbons may also beproduced through well 8328. In addition, condensed fluids may flowdownward in the direction of arrows 8336. The condensed fluids may beproduced through production well 8330. The heat source in productionwell 8330 may pyrolyze some of the produced hydrocarbons.

[2153] Heat form the heat sources and/or steam may mobilize somehydrocarbons at the migrating steam front. The mobilized hydrocarbonsmay flow downward in a direction substantially parallel to the front asindicated by arrow 8338. A portion of the mobilized hydrocarbons may bepyrolyzed. At least some of the mobilized hydrocarbons may be producedthrough production well 8328 or production well 8330.

[2154] In certain embodiments, existing steam treatmentprocesses/systems may be enhanced by the addition of one or more heatsources to the process/system. Heat sources may be placed in locationssuch that heat from the heat source openings will heat areas of theformation that are not heated (or that are less heated) by the steam.For example, if the steam is preferentially flowing in certain pathwaysthrough the formation, the heat sources may be placed in locations thatheat areas of the formations that are less heated by steam in thesepathways. In some embodiments, hydrocarbon fluids may be producedthrough a heel portion of a wellbore of a heat source. The heel portionof the heat source may be at a lower temperature than the toe portion ofthe heat source. Efficiency and production of hydrocarbons from a steamflood may be enhanced.

[2155] Some relatively permeable formations may contain a significantportion of adsorbed and/or absorbed methane. The formation may be in awater recharge zone. Only a small portion of the methane may be producedfrom relatively permeable formations without removing the formationwater. In some cases the inflow of water is so large that thehydrocarbon containing material cannot be dewatered effectively. Theremoval of the formation water may reduce pressure in the relativelypermeable formation and cause the release of some adsorbed methane. Theremoval of formation water may reduce pressure in the relativelypermeable formation and cause the release of some adsorbed methane. Insome embodiments, the dewatering process may result in recovery of up toabout 30% of adsorbed methane from a portion of the formation. In someembodiments, carbon dioxide may be injected into a formation to furtherenhance recovery of methane.

[2156] Increasing the average temperature of a formation with entrainedmethane may increase the yield of methane from the formation.Substantial recovery of entrained methane may be achieved at atemperature at or above approximately the boiling point of water in theformation. During heating, substantially all free moisture may beremoved from a portion of the formation after the portion has reached anaverage temperature of about the ambient boiling point of water.

[2157] Methane recovered from thermal desorption during heating may beused as fuel for an in situ treatment process. For example, methane maybe used for power generation to run electric heater wells. In addition,methane may be used as fuel for gas fired heater wells or combustionheaters.

[2158] All or almost all methane that is entrained in a hydrocarbonformation may be produced during an in situ conversion process. In anembodiment, freeze wells may be installed around a portion of aformation that includes adsorbed methane to define a treatment area.Heat sources, production wells, and/or dewatering wells may be installedin the treatment area prior to, simultaneously with, or afterinstallation of the freeze wells. The freeze wells may be activated toform a frozen barrier that inhibits water inflow into the treatmentarea. After formation of the frozen barrier, dewatering wells and/orselected production wells may be used to remove formation water from thetreatment area. Some of the methane entrained within the formation maybe released from the formation and recovered as the water is removed.Heat sources may be activated to begin heating the formation. Heat fromthe heat sources may release methane entrained in the formation. Themethane may be produced from production wells in the treatment area.Early production of adsorbed methane may significantly improve theeconomics of an in situ conversion process.

[2159] Water, in the form of saline or a solution with high levels ofdissolved solids, may be provided to a hot spent reservoir. Water to bedesalinated in a hot spent reservoir may originate from the ocean and/orfrom deep non-potable reservoirs. As water flows into the hot spentreservoir, the water may be evaporated and produced from the formationas steam. This water may be condensed into potable water having a lowtotal dissolved solids content.

[2160] Condensation of the produced water may occur in surfacefacilities or in subsurface conduits. Salts and other dissolved solidsmay remain in the reservoir. The salts and dissolved solids may bestored in the reservoir. Alternatively, effluent from surface facilitiesmay be provided to a hot spent formation for desalinization and/ordisposal.

[2161] Utilizing a hot spent formation to desalinate fluids may recoversome heat from the formation. After a temperature within the formationfalls below a boiling point of a fluid, desalinization may cease.Alternatively, a section of a formation may be continually heated tomaintain conditions appropriate for desalinization. Desalinization maycontinue until a permeability and/or a porosity of a section issignificantly reduced from the precipitation of solids. In someembodiments, heat from surface facilities may be used to run a surfacedesalinization plant, with produced salts and solids being injected intoa portion of the formation, or to preheat fluids being injected into theformation to minimize temperature change within the formation.

[2162] Water generated from a desalination process may be sold to alocal market for use as potable and/or agricultural water. Thedesalinated water may provide additional resources to geographical areasthat have severe water supply limitations.

[2163] Combustion of gaseous by-products from an in situ conversionprocess as well as fluids generated in surface facilities may beutilized to generate heat and/or energy for use in the in situconversion process. For example, a low heating value stream (LHVstream), such as tail gas from the treating/recovery operations, may becatalytically combusted to generate heat and increase temperatures to arange needed for the in situ conversion process. A monolithic substrate(i.e., honeycomb such as Torvex (Du Pont) and/or Cordierite (Corning))with good flow geometry and/or minimal pressure drops may be used in thecombustor. In a conventional process, a gaseous by-product stream may beflared, since the heating value is considered too low to sustain stablethermal combustion. Utilizing energy in these streams may increase anoverall efficiency of the treatment system for formations.

[2164] In this patent, certain U.S. patents, U.S. patent applications,and other materials (e.g., articles) have been incorporated byreference. The text of such U.S. patents, U.S. Pat. No. applications,and other materials is, however, only incorporated by reference to theextent that no conflict exists between such text and the otherstatements and drawings set forth herein. In the event of such conflict,then any such conflicting text in such incorporated by reference U.S.patents, U.S. patent applications, and other materials is specificallynot incorporated by reference in this patent.

[2165] Further modifications and alternative embodiments of variousaspects of the invention may be apparent to those skilled in the art inview of this description. Accordingly, this description is to beconstrued as illustrative only and is for the purpose of teaching thoseskilled in the art the general manner of carrying out the invention. Itis to be understood that the forms of the invention shown and describedherein are to be taken as the presently preferred embodiments. Elementsand materials may be substituted for those illustrated and describedherein, parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description of theinvention. Changes may be made in the elements described herein withoutdeparting from the spirit and scope of the invention as described in thefollowing claims.

What is claimed is:
 1. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 375° C.; and producing a mixture from the formation.
 2. The method of claim 1, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 3. The method of claim 1, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 4. The method of claim 1, wherein the one or more heat sources comprise electrical heaters.
 5. The method of claim 1, wherein the one or more heat sources comprise surface burners.
 6. The method of claim 1, wherein the one or more heat sources comprise flameless distributed combustors.
 7. The method of claim 1, wherein the one or more heat sources comprise natural distributed combustors.
 8. The method of claim 1, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 9. The method of claim 1, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to at least one of the one or more heat sources.
 10. The method of claim 1, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to a production well located in the formation.
 11. The method of claim 1, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 12. The method of claim 1, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 13. The method of claim 1, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.
 14. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 15. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 16. The method of claim 1, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 17. The method of claim 1, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 18. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 19. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 20. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 21. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 22. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 23. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 24. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 25. The method of claim 1, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 26. The method of claim 1, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 27. The method of claim 1, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 28. The method of claim 1, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 29. The method of claim 1, further comprising controlling formation conditions such that the produced mixture comprises a partial pressure of H₂ within the mixture greater than about 0.5 bars.
 30. The method of claim 29, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 31. The method of claim 1, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 32. The method of claim 1, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 33. The method of claim 1, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 34. The method of claim 1, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 35. The method of claim 1, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 36. The method of claim 35, wherein at least about 20 heat sources are disposed in the formation for each production well.
 37. The method of claim 1, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 38. The method of claim 1, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 39. The method of claim 1, further comprising separating the produced mixture into a gas stream and a liquid stream.
 40. The method of claim 1, further comprising separating the produced mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 41. The method of claim 1, wherein the produced mixture comprises H₂S, the method further comprising separating a portion of the H₂S from non-condensable hydrocarbons.
 42. The method of claim 1, wherein the produced mixture comprises CO₂, the method further comprising separating a portion of the CO₂ from non-condensable hydrocarbons.
 43. The method of claim 1, wherein the mixture is produced from a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.
 44. The method of claim 1, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 45. The method of claim 1, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture, wherein the mixture comprises a large non-condensable hydrocarbon gas component and H₂.
 46. The method of claim 1, wherein the minimum pyrolysis temperature is about 270° C.
 47. The method of claim 1, further comprising maintaining the pressure within the formation above about 2.0 bars absolute to inhibit production of fluids having carbon numbers above
 25. 48. The method of claim 1, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an amount of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to increase production of condensable hydrocarbons, and wherein the pressure is increased to increase production of non-condensable hydrocarbons.
 49. The method of claim 1, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an API gravity of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.
 50. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least the portion to a selected section of the formation substantially by conduction of heat; pyrolyzing at least some hydrocarbons within the selected section of the formation; and producing a mixture from the formation.
 51. The method of claim 50, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 52. The method of claim 50, wherein the one or more heat sources comprise electrical heaters.
 53. The method of claim 50, wherein the one or more heat sources comprise surface burners.
 54. The method of claim 50, wherein the one or more heat sources comprise flameless distributed combustors.
 55. The method of claim 50, wherein the one or more heat sources comprise natural distributed combustors.
 56. The method of claim 50, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 57. The method of claim 50, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0° C. per day during pyrolysis.
 58. The method of claim 50, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 59. The method of claim 50, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 60. The method of claim 50, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 61. The method of claim 50, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 62. The method of claim 50, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 63. The method of claim 50, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 64. The method of claim 50, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 65. The method of claim 50, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 66. The method of claim 50, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 67. The method of claim 50, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 68. The method of claim 50, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 69. The method of claim 50, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 70. The method of claim 50, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 71. The method of claim 50, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 72. The method of claim 50, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 73. The method of claim 50, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 74. The method of claim 73, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 75. The method of claim 50, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 76. The method of claim 50, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 77. The method of claim 50, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 78. The method of claim 50, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 79. The method of claim 50, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 80. The method of claim 79, wherein at least about 20 heat sources are disposed in the formation for each production well.
 81. The method of claim 50, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 82. The method of claim 50, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 83. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling the heat from the one or more heat sources such that an average temperature within at east a majority of the selected section of the formation is less than about 370° C. such that production of a substantial amount of hydrocarbons having carbon numbers greater than 25 is inhibited; controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least 2.0 bars absolute; and producing a mixture from the formation, wherein about 0.1% by weight of the produced mixture to about 15% by weight of the produced mixture are olefins, and wherein an average carbon number of the produced mixture is greater than 1 and less than about
 25. 84. The method of claim 83, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 85. The method of claim 83, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 86. The method of claim 83, wherein the one or more heat sources comprise electrical heaters.
 87. The method of claim 83, wherein the one or more heat sources comprise surface burners.
 88. The method of claim 83, wherein the one or more heat sources comprise flameless distributed combustors.
 89. The method of claim 83, wherein the one or more heat sources comprise natural distributed combustors.
 90. The method of claim 83, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 91. The method of claim 83, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 92. The method of claim 83, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 93. The method of claim 83, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 94. The method of claim 83, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 95. The method of claim 83, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 96. The method of claim 83, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 97. The method of claim 83, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 98. The method of claim 83, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 99. The method of claim 83, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 100. The method of claim 83, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 101. The method of claim 83, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 102. The method of claim 83, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 103. The method of claim 83, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 104. The method of claim 83, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 105. The method of claim 83, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 106. The method of claim 83, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 107. The method of claim 106, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 108. The method of claim 83, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 109. The method of claim 83, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 110. The method of claim 83, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 111. The method of claim 83, wherein producing the mixture comprises producing the mixture in a production welt, wherein at least about 7 heat sources are disposed in the formation for each production well.
 112. The method of claim 111, wherein at least about 20 heat sources are disposed in the formation for each production well.
 113. The method of claim 83, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 114. The method of claim 83, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 115. The method of claim 83, further comprising separating the produced mixture into a gas stream and a liquid stream.
 116. The method of claim 83, further comprising separating the produced mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 117. The method of claim 83, wherein the produced mixture comprises H₂S, the method further comprising separating a portion of the H₂S from non-condensable hydrocarbons.
 118. The method of claim 83, wherein the produced mixture comprises CO₂, the method further comprising separating a portion of the CO₂ from non-condensable hydrocarbons.
 119. The method of claim 83, wherein the mixture is produced from a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.
 120. The method of claim 83, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 121. The method of claim 83, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture, wherein the produced mixture comprise a large non-condensable hydrocarbon gas component and H₂.
 122. The method of claim 83, wherein the minimum pyrolysis temperature is about 270° C.
 123. The method of claim 83, further comprising maintaining the pressure within the formation above about 2.0 bars absolute to inhibit production of fluids having carbon numbers above
 25. 124. The method of claim 83, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an amount of condensable fluids within the produced mixture, wherein the pressure is reduced to increase production of condensable fluids, and wherein the pressure is increased to increase production of non-condensable fluids.
 125. The method of claim 83, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an API gravity of condensable fluids within the produced mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.
 126. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute; and producing a mixture from the formation.
 127. The method of claim 126, wherein controlling the pressure comprises controlling the pressure with a valve coupled to at least one of the one or more heat sources.
 128. The method of claim 126, wherein controlling the pressure comprises controlling the pressure with a valve coupled to a production well located in the formation.
 129. The method of claim 126, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 130. The method of claim 126, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 131. The method of claim 126, wherein the one or more heat sources comprise electrical heaters.
 132. The method of claim 126, wherein the one or more heat sources comprise surface burners.
 133. The method of claim 126, wherein the one or more heat sources comprise flameless distributed combustors.
 134. The method of claim 126, wherein the one or more heat sources comprise natural distributed combustors.
 135. The method of claim 126, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 136. The method of claim 126, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 137. The method of claim 126, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 138. The method of claim 126, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 139. The method of claim 126, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 140. The method of claim 126, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 141. The method of claim 126, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 142. The method of claim 126, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 143. The method of claim 126, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 144. The method of claim 126, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 145. The method of claim 126, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 146. The method of claim 126, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 147. The method of claim 126, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 148. The method of claim 126, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 149. The method of claim 126, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 150. The method of claim 126, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 151. The method of claim 126, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 152. The method of claim 126, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 153. The method of claim 152, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 154. The method of claim 126, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 155. The method of claim 126, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 156. The method of claim 126, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 157. The method of claim 126, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 158. The method of claim 126, wherein producing the mixture from the formation comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 159. The method of claim 158, wherein at least about 20 heat sources are disposed in the formation for each production well.
 160. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 375° C.; and producing a mixture from the formation.
 161. The method of claim 160, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 162. The method of claim 160, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 163. The method of claim 160, wherein the one or more heat sources comprise electrical heaters.
 164. The method of claim 160, wherein the one or more heat sources comprise surface burners.
 165. The method of claim 160, wherein the one or more heat sources comprise flameless distributed combustors.
 166. The method of claim 160, wherein the one or more heat sources comprise natural distributed combustors.
 167. The method of claim 160, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 168. The method of claim 160, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 169. The method of claim 160, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 170. The method of claim 160, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 171. The method of claim 160, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 172. The method of claim 160, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 173. The method of claim 160, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 174. The method of claim 160, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 175. The method of claim 160, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 176. The method of claim 160, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 177. The method of claim 160, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 178. The method of claim 160, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 179. The method of claim 160, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 180. The method of claim 160, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 181. The method of claim 160, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 182. The method of claim 160, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 183. The method of claim 160, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 184. The method of claim 160, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 185. The method of claim 160, wherein controlling the heat further comprises controlling the heat such that coke production is inhibited.
 186. The method of claim 160, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 187. The method of claim 186, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 188. The method of claim 160, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 189. The method of claim 160, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 190. The method of claim 160, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 191. The method of claim 160, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 192. The method of claim 160, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 193. The method of claim 192, wherein at least about 20 heat sources are disposed in the formation for each production well.
 194. The method of claim 160, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 195. The method of claim 160, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 196. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; producing a mixture from the formation, wherein at least a portion of the mixture is produced during the pyrolysis and the mixture moves through the formation in a vapor phase; and maintaining a pressure within at least a majority of the selected section above about 2.0 bars absolute.
 197. The method of claim 196, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 198. The method of claim 196, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 199. The method of claim 196, wherein the one or more heat sources comprise electrical heaters.
 200. The method of claim 196, wherein the one or more heat sources comprise surface burners.
 201. The method of claim 196, wherein the one or more heat sources comprise flameless distributed combustors.
 202. The method of claim 196, wherein the one or more heat sources comprise natural distributed combustors.
 203. The method of claim 196, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 204. The method of claim 196, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 205. The method of claim 196, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 206. The method of claim 196, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 207. The method of claim 196, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 208. The method of claim 196, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 209. The method of claim 196, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 210. The method of claim 196, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 211. The method of claim 196, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 212. The method of claim 196, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 213. The method of claim 196, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 214. The method of claim 196, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 215. The method of claim 196, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 216. The method of claim 196, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 217. The method of claim 196, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 218. The method of claim 196, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 219. The method of claim 196, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 220. The method of claim 196, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 221. The method of claim 196, wherein the pressure is measured at a wellhead of a production well.
 222. The method of claim 196, wherein the pressure is measured at a location within a wellbore of the production well.
 223. The method of claim 196, wherein the pressure is maintained below about 100 bars absolute.
 224. The method of claim 196, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 225. The method of claim 224, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 226. The method of claim 196, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 227. The method of claim 196, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 228. The method of claim 196, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 229. The method of claim 196, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 230. The method of claim 196, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 231. The method of claim 230, wherein at least about 20 heat sources are disposed in the formation for each production well.
 232. The method of claim 196, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 233. The method of claim 196, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 234. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; maintaining a pressure within at least a majority of the selected section of the formation above 2.0 bars absolute; and producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity higher than an API gravity of condensable hydrocarbons in a mixture producible from the formation at the same temperature and at atmospheric pressure.
 235. The method of claim 234, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 236. The method of claim 234, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 237. The method of claim 234, wherein the one or more heat sources comprise electrical heaters.
 238. The method of claim 234, wherein the one or more heat sources comprise surface burners.
 239. The method of claim 234, wherein the one or more heat sources comprise flameless distributed combustors.
 240. The method of claim 234, wherein the one or more heat sources comprise natural distributed combustors.
 241. The method of claim 234, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 242. The method of claim 234, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 243. The method of claim 234, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 244. The method of claim 234, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 245. The method of claim 234, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 246. The method of claim 234, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 247. The method of claim 234, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 248. The method of claim 234, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 249. The method of claim 234, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 250. The method of claim 234, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 251. The method of claim 234, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 252. The method of claim 234, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 253. The method of claim 234, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 254. The method of claim 234, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 255. The method of claim 234, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 256. The method of claim 234, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 257. The method of claim 234, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 258. The method of claim 234, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 259. The method of claim 234, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 260. The method of claim 234, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 261. The method of claim 234, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 262. The method of claim 234, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 263. The method of claim 234, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 264. The method of claim 234, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 265. The method of claim 234, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 266. The method of claim 265, wherein at least about 20 heat sources are disposed in the formation for each production well.
 267. The method of claim 234, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 268. The method of claim 234, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 269. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; maintaining a pressure within at least a majority of the selected section of the formation to above 2.0 bars absolute; and producing a fluid from the formation, wherein condensable hydrocarbons within the fluid comprise an atomic hydrogen to atomic carbon ratio of greater than about 1.75.
 270. The method of claim 269, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 271. The method of claim 269, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 272. The method of claim 269, wherein the one or more heat sources comprise electrical heaters.
 273. The method of claim 269, wherein the one or more heat sources comprise surface burners.
 274. The method of claim 269, wherein the one or more heat sources comprise flameless distributed combustors.
 275. The method of claim 269, wherein the one or more heat sources comprise natural distributed combustors.
 276. The method of claim 269, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 277. The method of claim 269, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 278. The method of claim 269, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 279. The method of claim 269, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 280. The method of claim 269, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 281. The method of claim 269, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 282. The method of claim 269, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 283. The method of claim 269, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 284. The method of claim 269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 285. The method of claim 269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 286. The method of claim 269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 287. The method of claim 269, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 288. The method of claim 269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 289. The method of claim 269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 290. The method of claim 269, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 291. The method of claim 269, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 292. The method of claim 269, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 293. The method of claim 269, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 294. The method of claim 269, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 295. The method of claim 269, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 296. The method of claim 269, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 297. The method of claim 269, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 298. The method of claim 269, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 299. The method of claim 269, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 300. The method of claim 269, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 301. The method of claim 300, wherein at least about 20 heat sources are disposed in the formation for each production well.
 302. The method of claim 269, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 303. The method of claim 269, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 304. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; maintaining a pressure within at least a majority of the selected section of the formation to above 2.0 bars absolute; and producing a mixture from the formation, wherein the produced mixture comprises a higher amount of non-condensable components as compared to non-condensable components producible from the formation under the same temperature conditions and at atmospheric pressure.
 305. The method of claim 304, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 306. The method of claim 304, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 307. The method of claim 304, wherein the one or more heat sources comprise electrical heaters.
 308. The method of claim 304, wherein the one or more heat sources comprise surface burners.
 309. The method of claim 304, wherein the one or more heat sources comprise flameless distributed combustors.
 310. The method of claim 304, wherein the one or more heat sources comprise natural distributed combustors.
 311. The method of claim 304, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 312. The method of claim 304, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 313. The method of claim 304, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 314. The method of claim 304, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 315. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 316. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 317. The method of claim 304, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 318. The method of claim 304, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 319. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 320. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 321. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 322. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 323. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 324. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 325. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 326. The method of claim 304, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 327. The method of claim 304, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 328. The method of claim 304, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 329. The method of claim 304, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 330. The method of claim 304, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 331. The method of claim 304, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 332. The method of claim 304, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 333. The method of claim 304, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 334. The method of claim 304, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 335. The method of claim 334, wherein at least about 20 heat sources are disposed in the formation for each production well.
 336. The method of claim 304, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 337. The method of claim 304, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 338. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that superimposed heat from the one or more heat sources pyrolyzes at least about 20% by weight of hydrocarbons within the selected section of the formation; and producing a mixture from the formation.
 339. The method of claim 338, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 340. The method of claim 338, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 341. The method of claim 338, wherein the one or more heat sources comprise electrical heaters.
 342. The method of claim 338, wherein the one or more heat sources comprise surface burners.
 343. The method of claim 338, wherein the one or more heat sources comprise flameless distributed combustors.
 344. The method of claim 338, wherein the one or more heat sources comprise natural distributed combustors.
 345. The method of claim 338, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 346. The method of claim 338, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 347. The method of claim 338, wherein providing heat from the one or more heat sources to at least the portion of formation comprises heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 348. The method of claim 338, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 349. The method of claim 338, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 350. The method of claim 338, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 351. The method of claim 338, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 352. The method of claim 338, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 353. The method of claim 338, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 354. The method of claim 338, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 355. The method of claim 338, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 356. The method of claim 338, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 357. The method of claim 338, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 358. The method of claim 338, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 359. The method of claim 338, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 360. The method of claim 338, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 361. The method of claim 338, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 362. The method of claim 338, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 363. The method of claim 338, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 364. The method of claim 338, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 365. The method of claim 338, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 366. The method of claim 338, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 367. The method of claim 338, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 368. The method of claim 338, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 369. The method of claim 338, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 370. The method of claim 338, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 371. The method of claim 370, wherein at least about 20 heat sources are disposed in the formation for each production well.
 372. The method of claim 338, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 373. The method of claim 338, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 374. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that superimposed heat from the one or more heat sources pyrolyzes at least about 20% of hydrocarbons within the selected section of the formation; and producing a mixture from the formation, wherein the mixture comprises a condensable component having an API gravity of at least about 25°.
 375. The method of claim 374, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 376. The method of claim 374, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 377. The method of claim 374, wherein the one or more heat sources comprise electrical heaters.
 378. The method of claim 374, wherein the one or more heat sources comprise surface burners.
 379. The method of claim 374, wherein the one or more heat sources comprise flameless distributed combustors.
 380. The method of claim 374, wherein the one or more heat sources comprise natural distributed combustors.
 381. The method of claim 374, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 382. The method of claim 374, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 383. The method of claim 374, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 384. The method of claim 374, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 385. The method of claim 374, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 386. The method of claim 374, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 387. The method of claim 374, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 388. The method of claim 374, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 389. The method of claim 374, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 390. The method of claim 374, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 391. The method of claim 374, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 392. The method of claim 374, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 393. The method of claim 374, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 394. The method of claim 374, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 395. The method of claim 374, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 396. The method of claim 374, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 397. The method of claim 374, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 398. The method of claim 374, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 399. The method of claim 374, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 400. The method of claim 374, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 401. The method of claim 374, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 402. The method of claim 374, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 403. The method of claim 374, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 404. The method of claim 374, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 405. The method of claim 374, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 406. The method of claim 405, wherein at least about 20 heat sources are disposed in the formation for each production well.
 407. The method of claim 374, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 408. The method of claim 374, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 409. A method of treating a layer of a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the layer, wherein the one or more heat sources are positioned proximate an edge of the layer; allowing the heat to transfer from the one or more heat sources to a selected section of the layer such that superimposed heat from the one or more heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation; and producing a mixture from the formation.
 410. The method of claim 409, wherein the one or more heat sources are laterally spaced from a center of the layer.
 411. The method of claim 409, wherein the one or more heat sources are positioned in a staggered line.
 412. The method of claim 409, wherein the one or more heat sources positioned proximate the edge of the layer can increase an amount of hydrocarbons produced per unit of energy input to the one or more heat sources.
 413. The method of claim 409, wherein the one or more heat sources positioned proximate the edge of the layer can increase the volume of formation undergoing pyrolysis per unit of energy input to the one or more heat sources.
 414. The method of claim 409, wherein the one or more heat sources comprise electrical heaters.
 415. The method of claim 409, wherein the one or more heat sources comprise surface burners.
 416. The method of claim 409, wherein the one or more heat sources comprise flameless distributed combustors.
 417. The method of claim 409, wherein the one or more heat sources comprise natural distributed combustors.
 418. The method of claim 409, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 419. The method of claim 409, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0° C. per day during pyrolysis.
 420. The method of claim 409, wherein providing heat from the one or more heat sources to at least the portion of the layer comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 421. The method of claim 409, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 422. The method of claim 409, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 423. The method of claim 409, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 424. The method of claim 409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 425. The method of claim 409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 426. The method of claim 409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 427. The method of claim 409, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 428. The method of claim 409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 429. The method of claim 409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 430. The method of claim 409, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 431. The method of claim 409, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 432. The method of claim 409, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 433. The method of claim 409, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 434. The method of claim 409, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 435. The method of claim 409, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 436. The method of claim 435, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 437. The method of claim 409, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 438. The method of claim 409, further comprising controlling formation conditions, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 439. The method of claim 409, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 440. The method of claim 409, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 441. The method of claim 409, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 442. The method of claim 441, wherein at least about 20 heat sources are disposed in the formation for each production well.
 443. The method of claim 409, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 444. The method of claim 409, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 445. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure; and producing a mixture from the formation.
 446. The method of claim 445, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 447. The method of claim 445, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 448. The method of claim 445, wherein the one or more heat sources comprise electrical heaters.
 449. The method of claim 445, wherein the one or more heat sources comprise surface burners.
 450. The method of claim 445, wherein the one or more heat sources comprise flameless distributed combustors.
 451. The method of claim 445, wherein the one or more heat sources comprise natural distributed combustors.
 452. The method of claim 445, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 453. The method of claim 445, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 454. The method of claim 445, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 455. The method of claim 445, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 456. The method of claim 445, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 457. The method of claim 445, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 458. The method of claim 445, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 459. The method of claim 445, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 460. The method of claim 445, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 461. The method of claim 445, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 462. The method of claim 445, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 463. The method of claim 445, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 464. The method of claim 445, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 465. The method of claim 445, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 466. The method of claim 445, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 467. The method of claim 445, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 468. The method of claim 445, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 469. The method of claim 445, wherein the controlled pressure is at least about 2.0 bars absolute.
 470. The method of claim 445, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 471. The method of claim 445, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 472. The method of claim 445, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 473. The method of claim 445, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 474. The method of claim 445, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 475. The method of claim 445, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 476. The method of claim 445, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 477. The method of claim 476, wherein at least about 20 heat sources are disposed in the formation for each production well.
 478. The method of claim 445, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 479. The method of claim 445, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 480. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section; producing a mixture from the formation; and controlling API gravity of the produced mixture to be greater than about 25 degrees API by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section: p=e ^([−44000/T+67]) where p is measured in psia and T is measured in ° Kelvin.
 481. The method of claim 480, wherein the API gravity of the produced mixture is controlled to be greater than about 30 degrees API, and wherein the equation is: p=e ^([−31000/T+51]).
 482. The method of claim 480, wherein the API gravity of the produced mixture is controlled to be greater than about 35 degrees API, and wherein the equation is: p=e ^([−22000/T+38]).
 483. The method of claim 480, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 484. The method of claim 480, wherein controlling the average temperature comprises maintaining a temperature in the selected section within a pyrolysis temperature range.
 485. The method of claim 480, wherein the one or more heat sources comprise electrical heaters.
 486. The method of claim 480, wherein the one or more heat sources comprise surface burners.
 487. The method of claim 480, wherein the one or more heat sources comprise flameless distributed combustors.
 488. The method of claim 480, wherein the one or more heat sources comprise natural distributed combustors.
 489. The method of claim 480, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 490. The method of claim 480, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 491. The method of claim 480, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 492. The method of claim 480, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 493. The method of claim 480, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 494. The method of claim 480, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 495. The method of claim 480, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 496. The method of claim 480, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 497. The method of claim 480, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 498. The method of claim 480, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 499. The method of claim 480, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 500. The method of claim 480, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 501. The method of claim 480, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 502. The method of claim 480, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 503. The method of claim 480, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 504. The method of claim 480, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 505. The method of claim 480, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 506. The method of claim 480, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 507. The method of claim 480, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 508. The method of claim 480, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 509. The method of claim 480, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 510. The method of claim 480, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 511. The method of claim 480, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 512. The method of claim 480, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 513. The method of claim 512, wherein at least about 20 heat sources are disposed in the formation for each production well.
 514. The method of claim 480, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 515. The method of claim 480, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 516. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat to at least a portion of a relatively permeable formation containing heavy hydrocarbons such that a temperature (T) in a substantial part of the heated portion exceeds 270° C. and hydrocarbons are pyrolyzed within the heated portion of the formation; controlling a pressure (p) within at least a substantial part of the heated portion of the formation; wherein p _(bar) >e ^([(−A/T)+B−2.6744]); wherein p is the pressure in bars absolute and T is the temperature in degrees K, and A and B are parameters that are larger than 10 and are selected in relation to the characteristics and composition of the relatively permeable formation containing heavy hydrocarbons and on the required olefin content and carbon number of the pyrolyzed hydrocarbon fluids; and producing pyrolyzed hydrocarbon fluids from the heated portion of the formation.
 517. The method of claim 516, wherein A is greater than 14000 and B is greater than about 25 and a majority of the produced pyrolyzed hydrocarbon fluids have an average carbon number lower than 25 and comprise less than about 10% by weight of olefins.
 518. The method of claim 516, wherein T is less than about 390° C., p is greater than about 1.4 bars, A is greater than about 44000, and b is greater than about 67, and a majority of the produced pyrolyzed hydrocarbon fluids have an average carbon number less than 25 and comprise less than 10% by weight of olefins.
 519. The method of claim 516, wherein T is less than about 390° C., p is greater than about 2 bars, A is less than about 57000, and b is less than about 83, and a majority of the produced pyrolyzed hydrocarbon fluids have an average carbon number lower than about
 21. 520. The method of claim 516, further comprising controlling the heat such that an average heating rate of the heated portion is less than about 3° C. per day during pyrolysis.
 521. The method of claim 516, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 522. The method of claim 516, wherein heat is transferred substantially by conduction from one or more heat sources to the heated portion of the formation.
 523. The method of claim 516, further comprising controlling formation conditions to produce a mixture of hydrocarbon fluids and H₂, wherein a partial pressure of H₂ within the mixture flowing through the formation is greater than 0.5 bars.
 524. The method of claim 523, further comprising, hydrogenating a portion of the produced pyrolyzed hydrocarbon fluids with at least a portion of the produced hydrogen and heating the fluids with heat from hydrogenation.
 525. The method of claim 516, wherein the substantially gaseous pyrolyzed hydrocarbon fluids are produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the hydrocarbon fluids within the wellbore.
 526. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section; producing a mixture from the formation; and controlling a weight percentage of olefins of the produced mixture to be less than about 20% by weight by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section: p=e ^([−57000/T+83]) where p is measured in psia and T is measured in ° Kelvin.
 527. The method of claim 526, wherein the weight percentage of olefins of the produced mixture is controlled to be less than about 10% by weight, and wherein the equation is: p=e ^([−16000/T+28]).
 528. The method of claim 526, wherein the weight percentage of olefins of the produced mixture is controlled to be less than about 5% by weight, and wherein the equation is: p=e ^([−12000/T+22]).
 529. The method of claim 526, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 530. The method of claim 526, wherein the one or more heat sources comprise electrical heaters.
 531. The method of claim 526, wherein the one or more heat sources comprise surface burners.
 532. The method of claim 526, wherein the one or more heat sources comprise flameless distributed combustors.
 533. The method of claim 526, wherein the one or more heat sources comprise natural distributed combustors.
 534. The method of claim 526, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 535. The method of claim 534, wherein controlling an average temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 536. The method of claim 526, further comprising controlling the heat such that an average heating rate of the selected section is less than about 3.0° C. per day during pyrolysis.
 537. The method of claim 526, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 538. The method of claim 526, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 539. The method of claim 526, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 540. The method of claim 526, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 541. The method of claim 526, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 542. The method of claim 526, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 543. The method of claim 526, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 544. The method of claim 526, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 545. The method of claim 526, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 546. The method of claim 526, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 547. The method of claim 526, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 548. The method of claim 526, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 549. The method of claim 526, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 550. The method of claim 526, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 551. The method of claim 526, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 552. The method of claim 526, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 553. The method of claim 526, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 554. The method of claim 526, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 555. The method of claim 526, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 556. The method of claim 526, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 557. The method of claim 526, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 558. The method of claim 526, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 559. The method of claim 526, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 560. The method of claim 526, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 561. The method of claim 560, wherein at least about 20 heat sources are disposed in the formation for each production well.
 562. The method of claim 526, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 563. The method of claim 526, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 564. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: to providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section; producing a mixture from the formation; and controlling hydrocarbons having carbon numbers greater than 20 of the produced mixture to be less than about 20% by weight by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section: p=e ^([−14000/T+25]) where p is measured in psia and T is measured in ° Kelvin.
 565. The method of claim 564, wherein the hydrocarbons having carbon numbers greater than 20 of the produced mixture is controlled to be less than about 15% by weight, and wherein the equation is: p=e ^([−18000/T+32]).
 566. The method of claim 564, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 567. The method of claim 564, wherein the one or more heat sources comprise electrical heaters.
 568. The method of claim 564, wherein the one or more heat sources comprise surface burners.
 569. The method of claim 564, wherein the one or more heat sources comprise flameless distributed combustors.
 570. The method of claim 564, wherein the one or more heat sources comprise natural distributed combustors.
 571. The method of claim 564, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 572. The method of claim 571, wherein controlling the temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 573. The method of claim 564, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 574. The method of claim 564, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 575. The method of claim 564, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 576. The method of claim 564, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 577. The method of claim 564, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 578. The method of claim 564, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 579. The method of claim 564, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 580. The method of claim 564, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 581. The method of claim 564, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 582. The method of claim 564, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 583. The method of claim 564, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 584. The method of claim 564, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 585. The method of claim 564, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 586. The method of claim 564, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 587. The method of claim 564, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 588. The method of claim 564, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 589. The method of claim 564, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 590. The method of claim 564, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 591. The method of claim 564, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 592. The method of claim 564, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 593. The method of claim 564, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 594. The method of claim 564, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 595. The method of claim 594, wherein at least about 20 heat sources are disposed in the formation for each production well.
 596. The method of claim 564, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 597. The method of claim 564, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 598. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section; producing a mixture from the formation; and controlling an atomic hydrogen to carbon ratio of the produced mixture to be greater than about 1.7 by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section: p=e ^([−38000/T+61]) where p is measured in psia and T is measured in ° Kelvin.
 599. The method of claim 598, wherein the atomic hydrogen to carbon ratio of the produced mixture is controlled to be greater than about 1.8, and wherein the equation is: p=e ^([−13000/T+24]).
 600. The method of claim 598, wherein the atomic hydrogen to carbon ratio of the produced mixture is controlled to be greater than about 1.9, and wherein the equation is: p=e ^([−8000/T+18]).
 601. The method of claim 598, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 602. The method of claim 598, wherein the one or more heat sources comprise electrical heaters.
 603. The method of claim 598, wherein the one or more heat sources comprise surface burners.
 604. The method of claim 598, wherein the one or more heat sources comprise flameless distributed combustors.
 605. The method of claim 598, wherein the one or more heat sources comprise natural distributed combustors.
 606. The method of claim 598, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 607. The method of claim 606, wherein controlling the temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 608. The method of claim 598, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 609. The method of claim 598, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 610. The method of claim 598, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 611. The method of claim 598, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 612. The method of claim 598, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 613. The method of claim 598, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 614. The method of claim 598, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 615. The method of claim 598, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 616. The method of claim 598, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 617. The method of claim 598, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 618. The method of claim 598, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 619. The method of claim 598, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 620. The method of claim 598, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 621. The method of claim 598, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 622. The method of claim 598, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 623. The method of claim 598, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 624. The method of claim 598, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 625. The method of claim 598, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 626. The method of claim 598, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 627. The method of claim 598, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 628. The method of claim 598, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 629. The method of claim 598, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 630. The method of claim 598, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 631. The method of claim 598, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 632. The method of claim 631, wherein at least about 20 heat sources are disposed in the formation for each production well.
 633. The method of claim 598, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 634. The method of claim 598, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 635. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling a pressure-temperature relationship within at least the selected section of the formation by selected energy input into the one or more heat sources and by pressure release from the selected section through wellbores of the one or more heat sources; and producing a mixture from the formation.
 636. The method of claim 635, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 637. The method of claim 635, wherein the one or more heat sources comprise at least two heat sources.
 638. The method of claim 635, wherein the one or more heat sources comprise surface burners.
 639. The method of claim 635, wherein the one or more heat sources comprise flameless distributed combustors.
 640. The method of claim 635, wherein the one or more heat sources comprise natural distributed combustors.
 641. The method of claim 635, further comprising controlling the pressure-temperature relationship by controlling a rate of removal of fluid from the formation.
 642. The method of claim 635, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 643. The method of claim 635, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 644. The method of claim 635, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 645. The method of claim 635, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 646. The method of claim 635, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 647. The method of claim 635, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 648. The method of claim 635, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 649. The method of claim 635, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 650. The method of claim 635, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 651. The method of claim 635, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 652. The method of claim 635, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 653. The method of claim 635, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 654. The method of claim 635, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 655. The method of claim 635, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 656. The method of claim 635, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 657. The method of claim 635, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 658. The method of claim 635, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 659. The method of claim 635, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 660. The method of claim 635, further comprising controlling formation conditions to produce a mixture of hydrocarbon fluids and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 661. The method of claim 635, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 662. The method of claim 635, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 663. The method of claim 635, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 664. The method of claim 635, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 665. The method of claim 635, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 666. The method of claim 635, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 667. The method of claim 635, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 668. The method of claim 667, wherein at least about 20 heat sources are disposed in the formation for each production well.
 669. The method of claim 635, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 670. The method of claim 635, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 671. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons, wherein formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 672. The method of claim 671, wherein heating a selected volume comprises heating with an electrical heater.
 673. The method of claim 671, wherein heating a selected volume comprises heating with a surface burner.
 674. The method of claim 671, wherein heating a selected volume comprises heating with a flameless distributed combustor.
 675. The method of claim 671, wherein heating a selected volume comprises heating with at least one natural distributed combustor.
 676. The method of claim 671, further comprising controlling a pressure and a temperature within at least a majority of the selected volume of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 677. The method of claim 671, further comprising controlling the heating such that an average heating rate of the selected volume is less than about 1° C. per day during pyrolysis.
 678. The method of claim 671, wherein a value for C_(v) is determined as an average heat capacity of two or more samples taken from the relatively permeable formation containing heavy hydrocarbons.
 679. The method of claim 671, wherein heating the selected volume comprises transferring heat substantially by conduction.
 680. The method of claim 671, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 681. The method of claim 671, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 682. The method of claim 671, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 683. The method of claim 671, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 684. The method of claim 671, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 685. The method of claim 671, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 686. The method of claim 671, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 687. The method of claim 671, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 688. The method of claim 671, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 689. The method of claim 671, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 690. The method of claim 671, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 691. The method of claim 671, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 692. The method of claim 671, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 693. The method of claim 671, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 694. The method of claim 671, further comprising controlling a pressure within at least a majority of the selected volume of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 695. The method of claim 671, further comprising controlling formation conditions to produce a mixture from the formation comprising condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 696. The method of claim 671, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 697. The method of claim 671, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 698. The method of claim 671, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 699. The method of claim 671, further comprising: providing hydrogen (H₂) to the heated volume to hydrogenate hydrocarbons within the volume; and heating a portion of the volume with heat from hydrogenation.
 700. The method of claim 671, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 701. The method of claim 671, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 702. The method of claim 701, wherein at least about 20 heat sources are disposed in the formation for each production well.
 703. The method of claim 671, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 704. The method of claim 671, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 705. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section; controlling heat output from the one or more heat sources such that an average heating rate of the selected section rises by less than about 3° C. per day when the average temperature of the selected section is at, or above, the temperature that will pyrolyze hydrocarbons within the selected section; and producing a mixture from the formation.
 706. The method of claim 705, wherein controlling heat output comprises: raising the average temperature within the selected section to a first temperature that is at or above a minimum pyrolysis temperature of hydrocarbons within the formation; limiting energy input into the one or more heat sources to inhibit increase in temperature of the selected section; and increasing energy input into the formation to raise an average temperature of the selected section above the first temperature when production of formation fluid declines below a desired production rate.
 707. The method of claim 705, wherein controlling heat output comprises: raising the average temperature within the selected section to a first temperature that is at or above a minimum pyrolysis temperature of hydrocarbons within the formation; limiting energy input into the one or more heat sources to inhibit increase in temperature of the selected section; and increasing energy input into the formation to raise an average temperature of the selected section above the first temperature when quality of formation fluid produced from the formation falls below a desired quality.
 708. The method of claim 705, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section.
 709. The method of claim 705, wherein the one or more heat sources comprise electrical heaters.
 710. The method of claim 705, wherein the one or more heat sources comprise surface burners.
 711. The method of claim 705, wherein the one or more heat sources comprise Blameless distributed combustors.
 712. The method of claim 705, wherein the one or more heat sources comprise natural distributed combustors.
 713. The method of claim 705, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 714. The method of claim 705, wherein the heat is controlled such that an average heating rate of the selected section is less than about 1.5° C. per day during pyrolysis.
 715. The method of claim 705, wherein the heat is controlled such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 716. The method of claim 705, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density.
 717. The method of claim 705, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 718. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 719. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 720. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons, wherein the condensable hydrocarbons have an olefin content less than about 2.5% by weight of the condensable hydrocarbons, and wherein the olefin content is greater than about 0.1% by weight of the condensable hydrocarbons.
 721. The method of claim 705, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 722. The method of claim 705, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.10 and wherein the ratio of ethene to ethane is greater than about 0.001.
 723. The method of claim 705, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.05 and wherein the ratio of ethene to ethane is greater than about 0.001.
 724. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 725. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 726. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 727. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 728. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 729. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 730. The method of claim 705, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 731. The method of claim 705, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 732. The method of claim 705, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 733. The method of claim 705, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 734. The method of claim 705, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 735. The method of claim 705, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 736. The method of claim 705, wherein a partial pressure of H₂ is measured when the mixture is at a production well.
 737. The method of claim 705, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 738. The method of claim 705, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 739. The method of claim 705, further comprising: providing H₂ to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 740. The method of claim 705, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 741. The method of claim 705, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 742. The method of claim 741, wherein at least about 20 heat sources are disposed in the formation for each production well.
 743. The method of claim 705, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 744. The method of claim 705, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 745. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; to heat a selected section of the formation to an average temperature above about 270° C.; allowing the heat to transfer from the one or more heat sources to the selected section of the formation; controlling the heat from the one or more heat sources such that an average heating rate of the selected section is less than about 3° C. per day during pyrolysis; and producing a mixture from the formation.
 746. The method of claim 745, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 747. The method of claim 745, wherein the one or more heat sources comprise electrical heaters.
 748. The method of claim 745, further comprising supplying electricity to the electrical heaters substantially during non-peak hours.
 749. The method of claim 745, wherein the one or more heat sources comprise surface burners.
 750. The method of claim 745, wherein the one or more heat sources comprise flameless distributed combustors.
 751. The method of claim 745, wherein the one or more heat sources comprise natural distributed combustors.
 752. The method of claim 745, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 753. The method of claim 745, wherein the heat is further controlled such that an average heating rate of the selected section is less than about 3° C./day until production of condensable hydrocarbons substantially ceases.
 754. The method of claim 745, wherein the heat is further controlled such that an average heating rate of the selected section is less than about 1.5° C. per day during pyrolysis.
 755. The method of claim 745, wherein the heat is further controlled such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 756. The method of claim 745, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density.
 757. The method of claim 745, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 758. The method of claim 745, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 759. The method of claim 745, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 760. The method of claim 745, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 761. The method of claim 745, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 762. The method of claim 745, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 763. The method of claim 745, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 764. The method of claim 745, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 765. The method of claim 745, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 766. The method of claim 745, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 767. The method of claim 745, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 768. The method of claim 745, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 769. The method of claim 745, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 770. The method of claim 745, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 771. The method of claim 745, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 772. The method of claim 745, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 773. The method of claim 745, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 774. The method of claim 773, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 775. The method of claim 745, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 776. The method of claim 745, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 777. The method of claim 745, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 778. The method of claim 745, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 779. The method of claim 745, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 780. The method of claim 779, wherein at least about 20 heat sources are disposed in the formation for each production well.
 781. The method of claim 745, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 782. The method of claim 745, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 783. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; producing a mixture from the formation through at least one production well; monitoring a temperature at or in the production well; and controlling heat input to raise the monitored temperature at a rate of less than about 3° C. per day.
 784. The method of claim 783, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 785. The method of claim 783, wherein the one or more heat sources comprise electrical heaters.
 786. The method of claim 783, wherein the one or more heat sources comprise surface burners.
 787. The method of claim 783, wherein the one or more heat sources comprise flameless distributed combustors.
 788. The method of claim 783, wherein the one or more heat sources comprise natural distributed combustors.
 789. The method of claim 783, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 790. The method of claim 783, wherein the heat is controlled such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 791. The method of claim 783, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density.
 792. The method of claim 783, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 793. The method of claim 783, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 794. The method of claim 783, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 795. The method of claim 783, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 796. The method of claim 783, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 797. The method of claim 783, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 798. The method of claim 783, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 799. The method of claim 783, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 800. The method of claim 783, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 801. The method of claim 783, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 802. The method of claim 783, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 803. The method of claim 783, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 804. The method of claim 783, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 805. The method of claim 783, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 806. The method of claim 783, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 807. The method of claim 783, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 808. The method of claim 807, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 809. The method of claim 783, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 810. The method of claim 783, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 811. The method of claim 783, further comprising: providing H₂ to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 812. The method of claim 783, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 813. The method of claim 783, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 814. The method of claim 813, wherein at least about 20 heat sources are disposed in the formation for each production well.
 815. The method of claim 783, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 816. The method of claim 783, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 817. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: heating a portion of the formation to a temperature sufficient to support oxidation of hydrocarbons within the portion, wherein the portion is located substantially adjacent to a wellbore; flowing an oxidant through a conduit positioned within the wellbore to a heat source zone within the portion, wherein the heat source zone supports an oxidation reaction between hydrocarbons and the oxidant; reacting a portion of the oxidant with hydrocarbons to generate heat; and transferring generated heat substantially by conduction to a pyrolysis zone of the formation to pyrolyze at least a portion of the hydrocarbons within the pyrolysis zone.
 818. The method of claim 817, wherein heating the portion of the formation comprises raising a temperature of the portion above about 400° C.
 819. The method of claim 817, wherein the conduit comprises critical flow orifices, the method further comprising flowing the oxidant through the critical flow orifices to the heat source zone.
 820. The method of claim 817, further comprising removing reaction products from the heat source zone through the wellbore.
 821. The method of claim 817, further comprising removing excess oxidant from the heat source zone to inhibit transport of the oxidant to the pyrolysis zone.
 822. The method of claim 817, further comprising transporting the oxidant from the conduit to the heat source zone substantially by diffusion.
 823. The method of claim 817, further comprising heating the conduit with reaction products being removed through the wellbore.
 824. The method of claim 817, wherein the oxidant comprises hydrogen peroxide.
 825. The method of claim 817, wherein the oxidant comprises air.
 826. The method of claim 817, wherein the oxidant comprises a fluid substantially free of nitrogen.
 827. The method of claim 817, further comprising limiting an amount of oxidant to maintain a temperature of the heat source zone less than about 1200° C.
 828. The method of claim 817, wherein heating the portion of the formation comprises electrically heating the formation.
 829. The method of claim 817, wherein heating the portion of the formation comprises heating the portion using exhaust gases from a surface burner.
 830. The method of claim 817, wherein heating the portion of the formation comprises heating the portion with a flameless distributed combustor.
 831. The method of claim 817, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 832. The method of claim 817, further comprising controlling the heat such that an average heating rate of the pyrolysis zone is less than about 1° C. per day during pyrolysis.
 833. The method of claim 817, further comprising controlling a pressure within at least a majority of the pyrolysis zone of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 834. The method of claim 817, further comprising: providing hydrogen (H₂) to the pyrolysis zone to hydrogenate hydrocarbons within the pyrolysis zone; and heating a portion of the pyrolysis zone with heat from hydrogenation.
 835. The method of claim 817, wherein the wellbore is located along strike to reduce pressure differentials along a heated length of the wellbore.
 836. The method of claim 817, wherein the wellbore is located along strike to increase uniformity of heating along a heated length of the wellbore.
 837. The method of claim 817, wherein the wellbore is located along strike to increase control of heating along a heated length of the wellbore.
 838. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidant; flowing the oxidant into a conduit, and wherein the conduit is connected such that the oxidant can flow from the conduit to the hydrocarbons; allowing the oxidant and the hydrocarbons to react to produce heat in a heat source zone; allowing heat to transfer from the heat source zone to a pyrolysis zone in the formation to pyrolyze at least a portion of the hydrocarbons within the pyrolysis zone; and removing reaction products such that the reaction products are inhibited from flowing from the heat source zone to the pyrolysis zone.
 839. The method of claim 838, wherein heating the portion of the formation comprises raising the temperature of the portion above about 400° C.
 840. The method of claim 838, wherein heating the portion of the formation comprises electrically heating the formation.
 841. The method of claim 838, wherein heating the portion of the formation comprises heating the portion using exhaust gases from a surface burner.
 842. The method of claim 838, wherein the conduit comprises critical flow orifices, the method further comprising flowing the oxidant through the critical flow orifices to the heat source zone.
 843. The method of claim 838, wherein the conduit is located with in a wellbore, wherein removing reaction products comprises removing reaction products from the heat source zone through the wellbore.
 844. The method of claim 838, further comprising removing excess oxidant from the heat source zone to inhibit transport of the oxidant to the pyrolysis zone.
 845. The method of claim 838, further comprising transporting the oxidant from the conduit to the heat source zone substantially by diffusion.
 846. The method of claim 838, wherein the conduit is located within a wellbore, the method further comprising heating the conduit with reaction products being removed through the wellbore to raise a temperature of the oxidant passing through the conduit.
 847. The method of claim 838, wherein the oxidant comprises hydrogen peroxide.
 848. The method of claim 838, wherein the oxidant comprises air.
 849. The method of claim 838, wherein the oxidant comprises a fluid substantially free of nitrogen.
 850. The method of claim 838, further comprising limiting an amount of oxidant to maintain a temperature of the heat source zone less than about 1200° C.
 851. The method of claim 838, further comprising limiting an amount of oxidant to maintain a temperature of the heat source zone at a temperature that inhibits production of oxides of nitrogen.
 852. The method of claim 838, wherein heating a portion of the formation to a temperature sufficient to support oxidation of hydrocarbons within the portion further comprises heating with a flameless distributed combustor.
 853. The method of claim 838, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 854. The method of claim 838, further comprising controlling the heat such that an average heating rate of the pyrolysis zone is less than about 1° C. per day during pyrolysis.
 855. The method of claim 838, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 856. The method of claim 838, further comprising controlling a pressure within at least a majority of the pyrolysis zone, wherein the controlled pressure is at least about 2.0 bars absolute.
 857. The method of claim 838, further comprising: providing hydrogen (H₂) to the pyrolysis zone to hydrogenate hydrocarbons within the pyrolysis zone; and heating a portion of the pyrolysis zone with heat from hydrogenation.
 858. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein the portion is located substantially adjacent to an opening in the formation; providing the oxidizing fluid to a heat source zone in the formation; allowing the oxidizing gas to react with at least a portion of the hydrocarbons at the heat source zone to generate heat in the heat source zone; and transferring the generated heat substantially by conduction from the heat source zone to a pyrolysis zone in the formation.
 859. The method of claim 858, further comprising transporting the oxidizing fluid through the heat source zone by diffusion.
 860. The method of claim 858, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.
 861. The method of claim 858, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.
 862. The method of claim 858, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.
 863. The method of claim 858, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring substantial heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.
 864. The method of claim 858, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 865. The method of claim 858, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.
 866. The method of claim 858, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.
 867. The method of claim 858, wherein the heat source zone extends radially from the opening a width of less than approximately 0.15 m.
 868. The method of claim 858, wherein heating the portion comprises applying electrical current to an electric heater disposed within the opening.
 869. The method of claim 858, wherein the pyrolysis zone is substantially adjacent to the heat source zone.
 870. The method of claim 858, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 871. The method of claim 858, further comprising controlling the heat such that an average heating rate of the pyrolysis zone is less than about 1° C. per day during pyrolysis.
 872. The method of claim 858, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 873. The method of claim 858, further comprising controlling a pressure within at least a majority of the pyrolysis zone, wherein the controlled pressure is at least about 2.0 bars absolute.
 874. The method of claim 858, further comprising: providing hydrogen (H₂) to the pyrolysis zone to hydrogenate hydrocarbons within the pyrolysis zone; and heating a portion of the pyrolysis zone with heat from hydrogenation.
 875. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; producing a mixture from the formation; and maintaining an average temperature within the selected section above a minimum pyrolysis temperature and below a vaporization temperature of hydrocarbons having carbon numbers greater than 25 to inhibit production of a substantial amount of hydrocarbons having carbon numbers greater than 25 in the mixture.
 876. The method of claim 875, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 877. The method of claim 875, wherein maintaining the average temperature within the selected section comprises maintaining the temperature within a pyrolysis temperature range.
 878. The method of claim 875, wherein the one or more heat sources comprise electrical heaters.
 879. The method of claim 875, wherein the one or more heat sources comprise surface burners.
 880. The method of claim 875, wherein the one or more heat sources comprise flameless distributed combustors.
 881. The method of claim 875, wherein the one or more heat sources comprise natural distributed combustors.
 882. The method of claim 875, wherein the minimum pyrolysis temperature is greater than about 270 C.
 883. The method of claim 875, wherein the vaporization temperature is less than approximately 450° C. at atmospheric pressure.
 884. The method of claim 875, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 885. The method of claim 875, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 886. The method of claim 875, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 887. The method of claim 875, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 888. The method of claim 875, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 889. The method of claim 875, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 890. The method of claim 875, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 891. The method of claim 875, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 892. The method of claim 875, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 893. The method of claim 875, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 894. The method of claim 875, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 895. The method of claim 875, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 896. The method of claim 875, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 897. The method of claim 875, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 898. The method of claim 875, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 899. The method of claim 875, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 900. The method of claim 875, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 901. The method of claim 875, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 902. The method of claim 875, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 903. The method of claim 875, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 904. The method of claim 903, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 905. The method of claim 875, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 906. The method of claim 875, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 907. The method of claim 875, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 908. The method of claim 875, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 909. The method of claim 908, wherein at least about 20 heat sources are disposed in the formation for each production well.
 910. The method of claim 875, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 911. The method of claim 875, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 912. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than 25; and producing a mixture from the formation.
 913. The method of claim 912, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 914. The method of claim 912, wherein the one or more heat sources comprise electrical heaters.
 915. The method of claim 912, wherein the one or more heat sources comprise surface burners.
 916. The method of claim 912, wherein the one or more heat sources comprise flameless distributed combustors.
 917. The method of claim 912, wherein the one or more heat sources comprise natural distributed combustors.
 918. The method of claim 912, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 919. The method of claim 918, wherein controlling the temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 920. The method of claim 912, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 921. The method of claim 912, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 922. The method of claim 912, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 923. The method of claim 912, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 924. The method of claim 912, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 925. The method of claim 912, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 926. The method of claim 912, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 927. The method of claim 912, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 928. The method of claim 912, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 929. The method of claim 912, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 930. The method of claim 912, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 931. The method of claim 912, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 932. The method of claim 912, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 933. The method of claim 912, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 934. The method of claim 912, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 935. The method of claim 912, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 936. The method of claim 912, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 937. The method of claim 912, further comprising controlling the pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 938. The method of claim 912, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 939. The method of claim 938, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 940. The method of claim 912, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 941. The method of claim 912, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 942. The method of claim 912, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 943. The method of claim 912, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 944. The method of claim 943, wherein at least about 20 heat sources are disposed in the formation for each production well.
 945. The method of claim 912, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 946. The method of claim 912, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 947. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 948. The method of claim 947, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 949. The method of claim 947, wherein the one or more heat sources comprise electrical heaters.
 950. The method of claim 947, wherein the one or more heat sources comprise surface burners.
 951. The method of claim 947, wherein the one or more heat sources comprise flameless distributed combustors.
 952. The method of claim 947, wherein the one or more heat sources comprise natural distributed combustors.
 953. The method of claim 947, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 954. The method of claim 947, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.
 955. The method of claim 947, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 956. The method of claim 947, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 957. The method of claim 947, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 958. The method of claim 947, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at Least about 25°.
 959. The method of claim 947, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 960. The method of claim 947, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 961. The method of claim 947, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 962. The method of claim 947, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 963. The method of claim 947, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 964. The method of claim 947, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 965. The method of claim 947, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 966. The method of claim 947, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 967. The method of claim 947, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 968. The method of claim 947, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 969. The method of claim 947, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 970. The method of claim 947, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 971. The method of claim 947, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 972. The method of claim 947, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 973. The method of claim 947, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 974. The method of claim 973, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 975. The method of claim 947, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 976. The method of claim 947, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 977. The method of claim 947, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 978. The method of claim 947, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 979. The method of claim 947, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 980. The method of claim 979, wherein at least about 20 heat sources are disposed in the formation for each production well.
 981. The method of claim 947, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 982. The method of claim 947, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 983. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: heating a section of the formation to a pyrolysis temperature from at least a first heat source, a second heat source and a third heat source, and wherein the first heat source, the second heat source and the third heat source are located along a perimeter of the section; controlling heat input to the first heat source, the second heat source and the third heat source to limit a heating rate of the section to a rate configured to produce a mixture from the formation with an olefin content of less than about 15% by weight of condensable fluids (on a dry basis) within the produced mixture; and producing the mixture from the formation through a production well.
 984. The method of claim 983, wherein superposition of heat form the first heat source, second heat source, and third heat source pyrolyzes a portion of the hydrocarbons within the formation to fluids.
 985. The method of claim 983, wherein the pyrolysis temperature is between about 270° C. and about 400° C.
 986. The method of claim 983, wherein the first heat source is operated for less than about twenty four hours a day.
 987. The method of claim 983, wherein the first heat source comprises an electrical heater.
 988. The method of claim 983, wherein the first heat source comprises a surface burner.
 989. The method of claim 983, wherein the first heat source comprises a flameless distributed combustor.
 990. The method of claim 983, wherein the first heat source, second heat source and third heat source are positioned substantially at apexes of an equilateral triangle.
 991. The method of claim 983, wherein the production well is located substantially at a geometrical center of the first heat source, second heat source, and third heat source.
 992. The method of claim 983, further comprising a fourth heat source, fifth heat source, and sixth heat source located along the perimeter of the section.
 993. The method of claim 992, wherein the heat sources are located substantially at apexes of a regular hexagon.
 994. The method of claim 993, wherein the production well is located substantially at a center of the hexagon.
 995. The method of claim 983, further comprising controlling a pressure and a temperature within at least a majority of the section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 996. The method of claim 983, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.
 997. The method of claim 983, further comprising controlling the heat such that an average heating rate of the section is less than about 3° C. per day during pyrolysis.
 998. The method of claim 983, further comprising controlling the heat such that an average heating rate of the section is less than about 1° C. per day during pyrolysis.
 999. The method of claim 983, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1000. The method of claim 983, wherein heating the section of the formation comprises transferring heat substantially by conduction.
 1001. The method of claim 983, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1002. The method of claim 983, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1003. The method of claim 983, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 1004. The method of claim 983, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1005. The method of claim 983, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1006. The method of claim 983, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1007. The method of claim 983, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1008. The method of claim 983, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1009. The method of claim 983, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1010. The method of claim 983, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1011. The method of claim 983, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1012. The method of claim 983, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1013. The method of claim 983, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1014. The method of claim 983, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1015. The method of claim 983, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1016. The method of claim 1015, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 1017. The method of claim 983, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1018. The method of claim 983, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 1019. The method of claim 983, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1020. The method of claim 983, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1021. The method of claim 983, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1022. The method of claim 1021, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1023. The method of claim 983, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1024. The method of claim 983, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1025. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1026. The method of claim 1025, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1027. The method of claim 1025, wherein the one or more heat sources comprise electrical heaters.
 1028. The method of claim 1025, wherein the one or more heat sources comprise surface burners.
 1029. The method of claim 1025, wherein the one or more heat sources comprise flameless distributed combustors.
 1030. The method of claim 1025, wherein the one or more heat sources comprise natural distributed combustors.
 1031. The method of claim 1025, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1032. The method of claim 1031, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.
 1033. The method of claim 1025, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1034. The method of claim 1025, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1035. The method of claim 1025, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1036. The method of claim 1025, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1037. The method of claim 1025, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1038. The method of claim 1025, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 1039. The method of claim 1025, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 1040. The method of claim 1025, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1041. The method of claim 1025, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1042. The method of claim 1025, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1043. The method of claim 1025, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1044. The method of claim 1025, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1045. The method of claim 1025, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1046. The method of claim 1025, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1047. The method of claim 1025, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1048. The method of claim 1025, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1049. The method of claim 1025, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1050. The method of claim 1025, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1051. The method of claim 1050, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 1052. The method of claim 1025, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1053. The method of claim 1025, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 1054. The method of claim 1025, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1055. The method of claim 1025, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1056. The method of claim 1025, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1057. The method of claim 1056, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1058. The method of claim 1025, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1059. The method of claim 1025, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1060. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1061. The method of claim 1060, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1062. The method of claim 1060, wherein the one or more heat sources comprise electrical heaters.
 1063. The method of claim 1060, wherein the one or more heat sources comprise surface burners.
 1064. The method of claim 1060, wherein the one or more heat sources comprise flameless distributed combustors.
 1065. The method of claim 1060, wherein the one or more heat sources comprise natural distributed combustors.
 1066. The method of claim 1060, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1067. The method of claim 1066, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.
 1068. The method of claim 1060, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1069. The method of claim 1060, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1070. The method of claim 1060, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1071. The method of claim 1060, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1072. The method of claim 1060, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1073. The method of claim 1060, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 1074. The method of claim 1060, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 1075. The method of claim 1060, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1076. The method of claim 1060, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1077. The method of claim 1060, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1078. The method of claim 1060, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1079. The method of claim 1060, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1080. The method of claim 1060, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1081. The method of claim 1060, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1082. The method of claim 1060, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1083. The method of claim 1060, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1084. The method of claim 1060, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1085. The method of claim 1060, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1086. The method of claim 1060, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1087. The method of claim 1086, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 1088. The method of claim 1060, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1089. The method of claim 1060, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 1090. The method of claim 1060, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1091. The method of claim 1060, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1092. The method of claim 1060, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1093. The method of claim 1092, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1094. The method of claim 1060, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1095. The method of claim 1060, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1096. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1097. The method of claim 1096, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1098. The method of claim 1096, wherein the one or more heat sources comprise electrical heaters.
 1099. The method of claim 1096, wherein the one or more heat sources comprise surface burners.
 1100. The method of claim 1096, wherein the one or more heat sources comprise flameless distributed combustors.
 1101. The method of claim 1096, wherein the one or more heat sources comprise natural distributed combustors.
 1102. The method of claim 1096, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1103. The method of claim 1102, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.
 1104. The method of claim 1096, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1105. The method of claim 1096, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1106. The method of claim 1096, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1107. The method of claim 1096, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1108. The method of claim 1096, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1109. The method of claim 1096, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 1110. The method of claim 1096, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.
 1111. The method of claim 1096, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1112. The method of claim 1096, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1113. The method of claim 1096, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1114. The method of claim 1096, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1115. The method of claim 1096, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1116. The method of claim 1096, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1117. The method of claim 1096, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1118. The method of claim 1096, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1119. The method of claim 1096, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1120. The method of claim 1096, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1121. The method of claim 1096, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1122. The method of claim 1121, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 1123. The method of claim 1096, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1124. The method of claim 1096, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 1125. The method of claim 1096, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1126. The method of claim 1096, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1127. The method of claim 1096, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1128. The method of claim 1127, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1129. The method of claim 1096, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1130. The method of claim 1096, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1131. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: raising a temperature of a first section of the formation with one or more heat sources to a first pyrolysis temperature; heating the first section to an upper pyrolysis temperature, wherein heat is supplied to the first section at a rate configured to inhibit olefin production; producing a first mixture from the formation, wherein the first mixture comprises condensable hydrocarbons and H₂; creating a second mixture from the first mixture, wherein the second mixture comprises a higher concentration of H₂ than the first mixture; raising a temperature of a second section of the formation with one or more heat sources to a second pyrolysis temperature; providing a portion of the second mixture to the second section; heating the second section to an upper pyrolysis temperature, wherein heat is supplied to the second section at a rate configured to inhibit olefin production; and producing a third mixture from the second section.
 1132. The method of claim 1131, wherein creating the second mixture comprises removing condensable hydrocarbons from the first mixture.
 1133. The method of claim 1131, wherein creating the second mixture comprises removing water from the first mixture.
 1134. The method of claim 1131, wherein creating the second mixture comprises removing carbon dioxide from the first mixture.
 1135. The method of claim 1131, wherein the first pyrolysis temperature is greater than about 270 C.
 1136. The method of claim 1131, wherein the second pyrolysis temperature is greater than about 270° C.
 1137. The method of claim 1131, wherein the upper pyrolysis temperature is about 500° C.
 1138. The method of claim 1131, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the first or second selected section of the formation.
 1139. The method of claim 1131, wherein the one or more heat sources comprise electrical heaters.
 1140. The method of claim 1131, wherein the one or more heat sources comprise surface burners.
 1141. The method of claim 1131, wherein the one or more heat sources comprise flameless distributed combustors.
 1142. The method of claim 1131, wherein the one or more heat sources comprise natural distributed combustors.
 1143. The method of claim 1131, further comprising controlling a pressure and a temperature within at least a majority of the first section and the second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1144. The method of claim 1131, further comprising controlling the heat to the first and second sections such that an average heating rate of the first and second sections is less than about 1° C. per day during pyrolysis.
 1145. The method of claim 1131, wherein heating the first and the second sections comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1146. The method of claim 1131, wherein heating the first and second sections comprises transferring heat substantially by conduction.
 1147. The method of claim 1131, wherein the first or third mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1148. The method of claim 1131, wherein the first or third mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1149. The method of claim 1131, wherein the first or third mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1150. The method of claim 1131, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1151. The method of claim 1131, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1152. The method of claim 1131, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1153. The method of claim 1131, wherein the first or third mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1154. The method of claim 1131, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1155. The method of claim 1131, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1156. The method of claim 1131, wherein the first or third mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1157. The method of claim 1131, wherein the first or third mixture comprises a non-condensable component, and wherein the non-condensable component comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1158. The method of claim 1131, wherein the first or third mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1159. The method of claim 1131, wherein the first or third mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1160. The method of claim 1131, further comprising controlling a pressure within at least a majority of the first or second sections of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1161. The method of claim 1131, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1162. The method of claim 1161, wherein the partial pressure of H₂ within a mixture is measured when the mixture is at a production well.
 1163. The method of claim 1131, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1164. The method of claim 1131, further comprising: providing hydrogen (H₂) to the first or second section to hydrogenate hydrocarbons within the first or second section; and heating a portion of the first or second section with heat from hydrogenation.
 1165. The method of claim 1131, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1166. The method of claim 1131, wherein producing the first or third mixture comprises producing the first or third mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1167. The method of claim 1166, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1168. The method of claim 1131, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1169. The method of claim 1131, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1170. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the or a formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; producing a mixture from the formation; and hydrogenating a portion of the produced mixture with H₂ produced from the formation.
 1171. The method of claim 1170, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1172. The method of claim 1170, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1173. The method of claim 1170, wherein the one or more heat sources comprise electrical heaters.
 1174. The method of claim 1170, wherein the one or more heat sources comprise surface burners.
 1175. The method of claim 1170, wherein the one or more heat sources comprise flameless distributed combustors.
 1176. The method of claim 1170, wherein the one or more heat sources comprise natural distributed combustors.
 1177. The method of claim 1170, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1178. The method of claim 1170, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1179. The method of claim 1170, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1180. The method of claim 1170, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1181. The method of claim 1170, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1182. The method of claim 1170, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1183. The method of claim 1170, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1184. The method of claim 1170, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1185. The method of claim 1170, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1186. The method of claim 1170, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1187. The method of claim 1170, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1188. The method of claim 1170, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1189. The method of claim 1170, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1190. The method of claim 1170, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1191. The method of claim 1170, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1192. The method of claim 1170, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1193. The method of claim 1170, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1194. The method of claim 1170, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1195. The method of claim 1170, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1196. The method of claim 1170, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1197. The method of claim 1170, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1198. The method of claim 1170, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1199. The method of claim 1170, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1200. The method of claim 1199, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1201. The method of claim 1170, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1202. The method of claim 1170, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1203. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: heating a first section of the formation; producing H₂ from the first section of formation; heating a second section of the formation; and recirculating a portion of the H₂ from the first section into the second section of the formation to provide a reducing environment within the second section of the formation.
 1204. The method of claim 1203, wherein heating the first section or heating the second section comprises heating with an electrical heater.
 1205. The method of claim 1203, wherein heating the first section or heating the second section comprises heating with a surface burner.
 1206. The method of claim 1203, wherein heating the first section or heating the second section comprises heating with a flameless distributed combustor.
 1207. The method of claim 1203, wherein heating the first section or heating the second section comprises heating with a natural distributed combustor.
 1208. The method of claim 1203, further comprising controlling a pressure and a temperature within at least a majority of the first or second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1209. The method of claim 1203, further comprising controlling the heat such that an average heating rate of the first or second section is less than about 1° C. per day during pyrolysis.
 1210. The method of claim 1203, wherein heating the first section or heating the second section further comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1211. The method of claim 1203, wherein heating the first section or heating the second section comprises transferring heat substantially by conduction.
 1212. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1213. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1214. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1215. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1216. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than a bout 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1217. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1218. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1219. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1220. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1221. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons a re cycloalkanes.
 1222. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1223. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1224. The method of claim 1203, further comprising producing a mixture from the second section, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1225. The method of claim 1203, further comprising controlling a pressure within at least a majority of the first or second section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1226. The method of claim 1203, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1227. The method of claim 1226, wherein the partial pressure of H₂ within a mixture is measured when the mixture is at a production well.
 1228. The method of claim 1203, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1229. The method of claim 1203, further comprising: providing hydrogen (H₂) to the second section to hydrogenate hydrocarbons within the section; and heating a portion of the second section with heat from hydrogenation.
 1230. The method of claim 1203, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1231. The method of claim 1203, further comprising producing a mixture from the formation in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1232. The method of claim 1231, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1233. The method of claim 1203, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1234. The method of claim 1203, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1235. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; producing a mixture from the formation; and controlling formation conditions such that the mixture produced from the formation comprises condensable hydrocarbons including H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1236. The method of claim 1235, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1237. The method of claim 1235, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 1238. The method of claim 1235, wherein the one or more heat sources comprise electrical heaters.
 1239. The method of claim 1235, wherein the one or more heat sources comprise surface burners.
 1240. The method of claim 1235, wherein the one or more heat sources comprise flameless distributed combustors.
 1241. The method of claim 1235, wherein the one or more heat sources comprise natural distributed combustors.
 1242. The method of claim 1235, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1243. The method of claim 1235, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1244. The method of claim 1235, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1245. The method of claim 1235, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1246. The method of claim 1235, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1247. The method of claim 1235, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1248. The method of claim 1235, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1249. The method of claim 1235, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1250. The method of claim 1235, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1251. The method of claim 1235, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1252. The method of claim 1235, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1253. The method of claim 1235, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1254. The method of claim 1235, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1255. The method of claim 1235, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1256. The method of claim 1235, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1257. The method of claim 1235, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1258. The method of claim 1235, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1259. The method of claim 1235, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1260. The method of claim 1235, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1261. The method of claim 1235, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 1262. The method of claim 1235, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1263. The method of claim 1235, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1264. The method of claim 1235, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1265. The method of claim 1264, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1266. The method of claim 1235, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1267. The method of claim 1235, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1268. The method of claim 1235, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1269. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; maintaining a pressure of the selected section above atmospheric pressure to increase a partial pressure of H₂, as compared to the partial pressure of H₂ at atmospheric pressure, in at least a majority of the selected section; and producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1270. The method of claim 1269, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1271. The method of claim 1269, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1272. The method of claim 1269, wherein the one or more heat sources comprise electrical heaters.
 1273. The method of claim 1269, wherein the one or more heat sources comprise surface burners.
 1274. The method of claim 1269, wherein the one or more heat sources comprise flameless distributed combustors.
 1275. The method of claim 1269, wherein the one or more heat sources comprise natural distributed combustors.
 1276. The method of claim 1269, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1277. The method of claim 1269, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1278. The method of claim 1269, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1279. The method of claim 1269, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1280. The method of claim 1269, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1281. The method of claim 1269, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1282. The method of claim 1269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1283. The method of claim 1269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1284. The method of claim 1269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1285. The method of claim 1269, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1286. The method of claim 1269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1287. The method of claim 1269, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1288. The method of claim 1269, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1289. The method of claim 1269, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1290. The method of claim 1269, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1291. The method of claim 1269, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1292. The method of claim 1269, further comprising controlling the pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1293. The method of claim 1269, further comprising increasing the pressure of the selected section, to an upper limit of about 21 bars absolute, to increase an amount of non-condensable hydrocarbons produced from the formation.
 1294. The method of claim 1269, further comprising decreasing pressure of the selected section, to a lower limit of about atmospheric pressure, to increase an amount of condensable hydrocarbons produced from the formation.
 1295. The method of claim 1269, wherein the partial pressure comprises a partial pressure based on properties measured at a production well.
 1296. The method of claim 1269, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1297. The method of claim 1269, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1298. The method of claim 1269, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1299. The method of claim 1269, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1300. The method of claim 1269, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1301. The method of claim 1300, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1302. The method of claim 1269, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1303. The method of claim 1269, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1304. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing H₂ to the formation to produce a reducing environment in at least some of the formation; producing a mixture from the formation.
 1305. The method of claim 1304, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1306. The method of claim 1304, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1307. The method of claim 1304, further comprising separating a portion of hydrogen within the mixture and recirculating the portion into the formation.
 1308. The method of claim 1304, wherein the one or more heat sources comprise electrical heaters.
 1309. The method of claim 1304, wherein the one or more heat sources comprise surface burners.
 1310. The method of claim 1304, wherein the one or more heat sources comprise flameless distributed combustors.
 1311. The method of claim 1304, wherein the one or more heat sources comprise natural distributed combustors.
 1312. The method of claim 1304, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1313. The method of claim 1304, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1314. The method of claim 1304, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1315. The method of claim 1304, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1316. The method of claim 1304, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1317. The method of claim 1304, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1318. The method of claim 1304, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1319. The method of claim 1304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1320. The method of claim 1304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1321. The method of claim 1304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1322. The method of claim 1304, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1323. The method of claim 1304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1324. The method of claim 1304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1325. The method of claim 1304, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1326. The method of claim 1304, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1327. The method of claim 1304, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1328. The method of claim 1304, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1329. The method of claim 1304, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1330. The method of claim 1304, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1331. The method of claim 1304, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1332. The method of claim 1304, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1333. The method of claim 1304, wherein providing hydrogen (H₂) to the formation further comprises: hydrogenating hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1334. The method of claim 1304, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1335. The method of claim 1304, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1336. The method of claim 1335, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1337. The method of claim 1304, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1338. The method of claim 1304, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1339. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing H₂ to the selected section to hydrogenate hydrocarbons within the selected section and to heat a portion of the section with heat from the hydrogenation; and controlling heating of the selected section by controlling amounts of H₂ provided to the selected section.
 1340. The method of claim 1339, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1341. The method of claim 1339, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1342. The method of claim 1339, wherein the one or more heat sources comprise electrical heaters.
 1343. The method of claim 1339, wherein the one or more heat sources comprise surface burners.
 1344. The method of claim 1339, wherein the one or more heat sources comprise flameless distributed combustors.
 1345. The method of claim 1339, wherein the one or more heat sources comprise natural distributed combustors.
 1346. The method of claim 1339, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1347. The method of claim 1339, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1348. The method of claim 1339, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1349. The method of claim 1339, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1350. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1351. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1352. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1353. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1354. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1355. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1356. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1357. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1358. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1359. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1360. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1361. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1362. The method of claim 1339, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1363. The method of claim 1339, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1364. The method of claim 1339, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1365. The method of claim 1364, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1366. The method of claim 1339, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1367. The method of claim 1339, further comprising controlling formation conditions by recirculating a portion of hydrogen from a produced mixture into the formation.
 1368. The method of claim 1339, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1369. The method of claim 1339, further comprising producing a mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1370. The method of claim 1369, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1371. The method of claim 1339, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1372. The method of claim 1339, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1373. An in situ method for producing H₂ from a relatively permeable formation containing heavy hydrocarbons, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing a mixture from the formation, wherein a H₂ partial pressure within the mixture is greater than about 0.5 bars.
 1374. The method of claim 1373, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1375. The method of claim 1373, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1376. The method of claim 1373, wherein the one or more heat sources comprise electrical heaters.
 1377. The method of claim 1373, wherein the one or more heat sources comprise surface burners.
 1378. The method of claim 1373, wherein the one or more heat sources comprise flameless distributed combustors.
 1379. The method of claim 1373, wherein the one or more heat sources comprise natural distributed combustors.
 1380. The method of claim 1373, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1381. The method of claim 1373, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1382. The method of claim 1373, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1383. The method of claim 1373, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1384. The method of claim 1373, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1385. The method of claim 1373, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1386. The method of claim 1373, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1387. The method of claim 1373, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1388. The method of claim 1373, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1389. The method of claim 1373, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1390. The method of claim 1373, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1391. The method of claim 1373, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1392. The method of claim 1373, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1393. The method of claim 1373, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1394. The method of claim 1373, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1395. The method of claim 1373, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1396. The method of claim 1373, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1397. The method of claim 1373, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1398. The method of claim 1373, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1399. The method of claim 1373, further comprising recirculating a portion of the hydrogen within the mixture into the formation.
 1400. The method of claim 1373, further comprising condensing a hydrocarbon component from the produced mixture and hydrogenating the condensed hydrocarbons with a portion of the hydrogen.
 1401. The method of claim 1373, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1402. The method of claim 1373, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1403. The method of claim 1402, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1404. The method of claim 1373, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1405. The method of claim 1373, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1406. The method of claim 1373, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1407. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; wherein the selected section has been selected for heating using an atomic hydrogen weight percentage of at least a portion of hydrocarbons in the selected section, and wherein at least the portion of the hydrocarbons in the selected section comprises an atomic hydrogen weight percentage, when measured on a dry, ash-free basis, of greater than about 4.0%; and producing a mixture from the formation.
 1408. The method of claim 1407, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1409. The method of claim 1407, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1410. The method of claim 1407, wherein the one or more heat sources comprise electrical heaters.
 1411. The method of claim 1407, wherein the one or more heat sources comprise surface burners.
 1412. The method of claim 1407, wherein the one or more heat sources comprise flameless distributed combustors.
 1413. The method of claim 1407, wherein the one or more heat sources comprise natural distributed combustors.
 1414. The method of claim 1407, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1415. The method of claim 1407, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1416. The method of claim 1407, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1417. The method of claim 1407, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1418. The method of claim 1407, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1419. The method of claim 1407, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1420. The method of claim 1407, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1421. The method of claim 1407, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1422. The method of claim 1407, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1423. The method of claim 1407, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1424. The method of claim 1407, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1425. The method of claim 1407, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1426. The method of claim 1407, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1427. The method of claim 1407, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1428. The method of claim 1407, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1429. The method of claim 1407, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1430. The method of claim 1407, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1431. The method of claim 1407, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1432. The method of claim 1407, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1433. The method of claim 1432, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1434. The method of claim 1407, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1435. The method of claim 1407, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1436. The method of claim 1407, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1437. The method of claim 1407, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1438. The method of claim 1407, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1439. The method of claim 1438, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1440. The method of claim 1407, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1441. The method of claim 1407, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1442. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; wherein at least some hydrocarbons within the selected section have an initial atomic hydrogen weight percentage of greater than about 4.0%; and producing a mixture from the formation.
 1443. The method of claim 1442, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1444. The method of claim 1442, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1445. The method of claim 1442, wherein the one or more heat sources comprise electrical heaters.
 1446. The method of claim 1442, wherein the one or more heat sources comprise surface burners.
 1447. The method of claim 1442, wherein the one or more heat sources comprise flameless distributed combustors.
 1448. The method of claim 1442, wherein the one or more heat sources comprise natural distributed combustors.
 1449. The method of claim 1442, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1450. The method of claim 1442, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1451. The method of claim 1442, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1452. The method of claim 1442, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1453. The method of claim 1442, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1454. The method of claim 1442, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1455. The method of claim 1442, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1456. The method of claim 1442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1457. The method of claim 1442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1458. The method of claim 1442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1459. The method of claim 1442, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1460. The method of claim 1442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1461. The method of claim 1442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1462. The method of claim 1442, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1463. The method of claim 1442, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1464. The method of claim 1442, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1465. The method of claim 1442, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1466. The method of claim 1442, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1467. The method of claim 1442, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1468. The method of claim 1467, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1469. The method of claim 1442, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1470. The method of claim 1442, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1471. The method of claim 1442, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1472. The method of claim 1442, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1473. The method of claim 1442, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1474. The method of claim 1473, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1475. The method of claim 1442, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1476. The method of claim 1442, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1477. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; wherein the selected section has been selected for heating using a total organic matter weight percentage of at least a portion of the selected section, and wherein at least the portion of the selected section comprises a total organic matter weight percentage, of at least about 5.0%; and producing a mixture from the formation.
 1478. The method of claim 1477, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1479. The method of claim 1477, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1480. The method of claim 1477, wherein the one or more heat sources comprise electrical heaters.
 1481. The method of claim 1477, wherein the one or more heat sources comprise surface burners.
 1482. The method of claim 1477, wherein the one or more heat sources comprise flameless distributed combustors.
 1483. The method of claim 1477, wherein the one or more heat sources comprise natural distributed combustors.
 1484. The method of claim 1477, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1485. The method of claim 1477, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1486. The method of claim 1477, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1487. The method of claim 1477, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1488. The method of claim 1477, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1489. The method of claim 1477, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1490. The method of claim 1477, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1491. The method of claim 1477, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1492. The method of claim 1477, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1493. The method of claim 1477, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1494. The method of claim 1477, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1495. The method of claim 1477, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1496. The method of claim 1477, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1497. The method of claim 1477, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1498. The method of claim 1477, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1499. The method of claim 1477, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1500. The method of claim 1477, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1501. The method of claim 1477, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1502. The method of claim 1477, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1503. The method of claim 1502, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1504. The method of claim 1477, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1505. The method of claim 1477, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1506. The method of claim 1477, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1507. The method of claim 1477, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1508. The method of claim 1477, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1509. The method of claim 1508, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1510. The method of claim 1477, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1511. The method of claim 1477, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1512. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; wherein at least some hydrocarbons within the selected section have an initial total organic matter weight percentage of at least about 5.0%; and producing a mixture from the formation.
 1513. The method of claim 1512, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1514. The method of claim 1512, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1515. The method of claim 1512, wherein the one or more heat sources comprise electrical heaters.
 1516. The method of claim 1512, wherein the one or more heat sources comprise surface burners.
 1517. The method of claim 1512, wherein the one or more heat sources comprise flameless distributed combustors.
 1518. The method of claim 1512, wherein the one or more heat sources comprise natural distributed combustors.
 1519. The method of claim 1512, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1520. The method of claim 1512, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1521. The method of claim 1512, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1522. The method of claim 1512, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1523. The method of claim 1512, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1524. The method of claim 1512, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1525. The method of claim 1 512, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1526. The method of claim 1512, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1527. The method of claim 1512, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1528. The method of claim 1512, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1529. The method of claim 1512, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1530. The method of claim 1512, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1531. The method of claim 1512, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1532. The method of claim 1512, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1533. The method of claim 1512, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1534. The method of claim 1512, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1535. The method of claim 1512, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1536. The method of claim 1512, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1537. The method of claim 1512, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1538. The method of claim 1537, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1539. The method of claim 1512, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1540. The method of claim 1512, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1541. The method of claim 1512, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1542. The method of claim 1512, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1543. The method of claim 1512, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1544. The method of claim 1543, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1545. The method of claim 1512, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1546. The method of claim 1512, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1547. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; wherein the selected section has been selected for heating using an atomic hydrogen to carbon ratio of at least a portion of hydrocarbons in the selected section, wherein at least a portion of the hydrocarbons in the selected section comprises an atomic hydrogen to carbon ratio greater than about 0.70, and wherein the atomic hydrogen to carbon ratio is less than about 1.65; and producing a mixture from the formation.
 1548. The method of claim 1547, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1549. The method of claim 1547, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1550. The method of claim 1547, wherein the one or more heat sources comprise electrical heaters.
 1551. The method of claim 1547, wherein the one or more heat sources comprise surface burners.
 1552. The method of claim 1547, wherein the one or more heat sources comprise flameless distributed combustors.
 1553. The method of claim 1547, wherein the one or more heat sources comprise natural distributed combustors.
 1554. The method of claim 1547, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1555. The method of claim 1547, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1556. The method of claim 1547, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1557. The method of claim 1547, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1558. The method of claim 1547, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1559. The method of claim 1547, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1560. The method of claim 1547, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1561. The method of claim 1547, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1562. The method of claim 1547, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1563. The method of claim 1547, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1564. The method of claim 1547, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1565. The method of claim 1547, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1566. The method of claim 1547, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1567. The method of claim 1547, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1568. The method of claim 1547, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1569. The method of claim 1547, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1570. The method of claim 1547, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1571. The method of claim 1547, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1572. The method of claim 1547, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1573. The method of claim 1572, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1574. The method of claim 1547, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1575. The method of claim 1547, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1576. The method of claim 1547, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1577. The method of claim 1547, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1578. The method of claim 1547, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1579. The method of claim 1578, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1580. The method of claim 1547, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1581. The method of claim 1547, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1582. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to a selected section of the formation; allowing the heat to transfer from the one or more heat sources to the selected section of the formation to pyrolyze hydrocarbons within the selected section; wherein at least some hydrocarbons within the selected section have an initial atomic hydrogen to carbon ratio greater than about 0.70; wherein the initial atomic hydrogen to carbon ration is less than about 1.65; and producing a mixture from the formation.
 1583. The method of claim 1582, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1584. The method of claim 1582, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1585. The method of claim 1582, wherein the one or more heat sources comprise electrical heaters.
 1586. The method of claim 1582, wherein the one or more heat sources comprise surface burners.
 1587. The method of claim 1582, wherein the one or more heat sources comprise flameless distributed combustors.
 1588. The method of claim 1582, wherein the one or more heat sources comprise natural distributed combustors.
 1589. The method of claim 1582, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1590. The method of claim 1582, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1591. The method of claim 1582, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1592. The method of claim 1582, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1593. The method of claim 1582, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1594. The method of claim 1582, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1595. The method of claim 1582, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1596. The method of claim 1582, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1597. The method of claim 1582, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1598. The method of claim 1582, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1599. The method of claim 1582, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1600. The method of claim 1582, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1601. The method of claim 1582, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1602. The method of claim 1582, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1603. The method of claim 1582, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1604. The method of claim 1582, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1605. The method of claim 1582, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1606. The method of claim 1582, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1607. The method of claim 1582, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1608. The method of claim 1607, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1609. The method of claim 1582, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1610. The method of claim 1582, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1611. The method of claim 1582, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1612. The method of claim 1582, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1613. The method of claim 1582, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1614. The method of claim 1613, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1615. The method of claim 1582, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1616. The method of claim 1582, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1617. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; wherein the selected section has been selected for heating using a moisture content in the selected section, and wherein at least a portion of the selected section comprises a moisture content of less than about 15% by weight; and producing a mixture from the formation.
 1618. The method of claim 1617, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1619. The method of claim 1617, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1620. The method of claim 1617, wherein the one or more heat sources comprise electrical heaters.
 1621. The method of claim 1617, wherein the one or more heat sources comprise surface burners.
 1622. The method of claim 1617, wherein the one or more heat sources comprise flameless distributed combustors.
 1623. The method of claim 1617, wherein the one or more heat sources comprise natural distributed combustors.
 1624. The method of claim 1617, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1625. The method of claim 1617, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1626. The method of claim 1617, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1627. The method of claim 1617, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1628. The method of claim 1617, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1629. The method of claim 1617, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1630. The method of claim 1617, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1631. The method of claim 1617, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1632. The method of claim 1617, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1633. The method of claim 1617, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1634. The method of claim 1617, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1635. The method of claim 1617, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1636. The method of claim 1617, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1637. The method of claim 1617, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1638. The method of claim 1617, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1639. The method of claim 1617, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1640. The method of claim 1617, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1641. The method of claim 1617, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1642. The method of claim 1617, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1643. The method of claim 1642, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1644. The method of claim 1617, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1645. The method of claim 1617, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1646. The method of claim 1617, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1647. The method of claim 1617, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1648. The method of claim 1617, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1649. The method of claim 1648, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1650. The method of claim 1617, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1651. The method of claim 1617, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1652. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to a selected section of the formation; allowing the heat to transfer from the one or more heat sources to the selected section of the formation; wherein at least a portion of the selected section has an initial moisture content of less than about 15% by weight; and producing a mixture from the formation.
 1653. The method of claim 1652, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1654. The method of claim 1652, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1655. The method of claim 1652, wherein the one or more heat sources comprise electrical heaters.
 1656. The method of claim 1652, wherein the one or more heat sources comprise surface burners.
 1657. The method of claim 1652, wherein the one or more heat sources comprise flameless distributed combustors.
 1658. The method of claim 1652, wherein the one or more heat sources comprise natural distributed combustors.
 1659. The method of claim 1652, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1660. The method of claim 1652, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1661. The method of claim 1652, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1662. The method of claim 1652, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1663. The method of claim 1652, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1664. The method of claim 1652, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1665. The method of claim 1652, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1666. The method of claim 1652, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1667. The method of claim 1652, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1668. The method of claim 1652, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1669. The method of claim 1652, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1670. The method of claim 1652, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1671. The method of claim 1652, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1672. The method of claim 1652, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1673. The method of claim 1652, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1674. The method of claim 1652, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1675. The method of claim 1652, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1676. The method of claim 1652, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1677. The method of claim 1652, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1678. The method of claim 1677, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1679. The method of claim 1652, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1680. The method of claim 1652, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1681. The method of claim 1652, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1682. The method of claim 1652, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1683. The method of claim 1652, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1684. The method of claim 1683, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1685. The method of claim 1652, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1686. The method of claim 1652, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1687. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: pro viding heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; wherein the selected section is heated in a reducing environment during at least a portion of the time that the selected section is being heated; and producing a mixture from the formation.
 1688. The method of claim 1687, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1689. The method of claim 1687, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1690. The method of claim 1687, wherein the one or more heat sources comprise electrical heaters.
 1691. The method of claim 1687, wherein the one or more heat sources comprise surface burners.
 1692. The method of claim 1687, wherein the one or more heat sources comprise flameless distributed combustors.
 1693. The method of claim 1687, wherein the one or more heat sources comprise natural distributed combustors.
 1694. The method of claim 1687, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1695. The method of claim 1687, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1696. The method of claim 1687, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1697. The method of claim 1687, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1698. The method of claim 1687, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1699. The method of claim 1687, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1700. The method of claim 1687, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1701. The method of claim 1687, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1702. The method of claim 1687, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1703. The method of claim 1687, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1704. The method of claim 1687, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1705. The method of claim 1687, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1706. The method of claim 1687, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1707. The method of claim 1687, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1708. The method of claim 1687, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1709. The method of claim 1687, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1710. The method of claim 1687, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1711. The method of claim 1687, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1712. The method of claim 1687, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1713. The method of claim 1712, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1714. The method of claim 1687, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1715. The method of claim 1687, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1716. The method of claim 1687, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1717. The method of claim 1687, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1718. The method of claim 1687, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1719. The method of claim 1718, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1720. The method of claim 1687, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1721. The method of claim 1687, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1722. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: heating a first section of the formation to produce a mixture from the formation; heating a second section of the formation; and recirculating a portion of the produced mixture from the first section into the second section of the formation to provide a reducing environment within the second section of the formation.
 1723. The method of claim 1722, further comprising maintaining a temperature within the first section or the second section within a pyrolysis temperature range.
 1724. The method of claim 1722, wherein heating the first or the second section comprises heating with an electrical heater.
 1725. The method of claim 1722, wherein heating the first or the second section comprises heating with a surface burner.
 1726. The method of claim 1722, wherein heating the first or the second section comprises heating with a flameless distributed combustor.
 1727. The method of claim 1722, wherein heating the first or the second section comprises heating with a natural distributed combustor.
 1728. The method of claim 1722, further comprising controlling a pressure and a temperature within at least a majority of the first or second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1729. The method of claim 1722, further comprising controlling the heat such that an average heating rate of the first or the second section is less than about 1° C. per day during pyrolysis.
 1730. The method of claim 1722, wherein heating the first or the second section comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1731. The method of claim 1722, wherein heating the first or the second section comprises transferring heat substantially by conduction.
 1732. The method of claim 1722, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1733. The method of claim 1722, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1734. The method of claim 1722, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1735. The method of claim 1722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1736. The method of claim 1722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1737. The method of claim 1722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1738. The method of claim 1722, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1739. The method of claim 1722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1740. The method of claim 1722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1741. The method of claim 1722, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1742. The method of claim 1722, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1743. The method of claim 1722, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1744. The method of claim 1722, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1745. The method of claim 1722, further comprising controlling a pressure within at least a majority of the first or second section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1746. The method of claim 1722, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1747. The method of claim 1746, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1748. The method of claim 1722, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1749. The method of claim 1722, further comprising: providing hydrogen (H₂) to the first or second section to hydrogenate hydrocarbons within the first or second section; and heating a portion of the first or second section with heat from hydrogenation.
 1750. The method of claim 1722, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1751. The method of claim 1722, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1752. The method of claim 1751, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1753. The method of claim 1722, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1754. The method of claim 1722, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1755. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and controlling the heat to yield at least about 15% by weight of a total organic carbon content of at least some of the relatively permeable formation containing heavy hydrocarbons into condensable hydrocarbons.
 1756. The method of claim 1755, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1757. The method of claim 1755, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1758. The method of claim 1755, wherein the one or more heat sources comprise electrical heaters.
 1759. The method of claim 1755, wherein the one or more heat sources comprise surface burners.
 1760. The method of claim 1755, wherein the one or more heat sources comprise flameless distributed combustors.
 1761. The method of claim 1755, wherein the one or more heat sources comprise natural distributed combustors.
 1762. The method of claim 1755, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1763. The method of claim 1755, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1764. The method of claim 1755, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1765. The method of claim 1755, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1766. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1767. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons is are olefins.
 1768. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1769. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1770. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1771. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1772. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1773. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1774. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1775. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1776. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1777. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1778. The method of claim 1755, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1779. The method of claim 1755, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1780. The method of claim 1755, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1781. The method of claim 1755, further comprising producing a mixture from the formation, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1782. The method of claim 1755, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1783. The method of claim 1755, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1784. The method of claim 1755, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1785. The method of claim 1755, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1786. The method of claim 1755, further comprising producing a mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1787. The method of claim 1786, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1788. The method of claim 1755, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1789. The method of claim 1755, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1790. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and controlling the heat to yield greater than about 60% by weight of hydrocarbons.
 1791. The method of claim 1790, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1792. The method of claim 1790, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1793. The method of claim 1790, wherein the one or more heat sources comprise electrical heaters.
 1794. The method of claim 1790, wherein the one or more heat sources comprise surface burners.
 1795. The method of claim 1790, wherein the one or more heat sources comprise flameless distributed combustors.
 1796. The method of claim 1790, wherein the one or more heat sources comprise natural distributed combustors.
 1797. The method of claim 1790, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1798. The method of claim 1790, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1799. The method of claim 1790, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1800. The method of claim 1790, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1801. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1802. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1803. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15;
 1804. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1805. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1806. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1807. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1808. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1809. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1810. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1811. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1812. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1813. The method of claim 1790, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1814. The method of claim 1790, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1815. The method of claim 1790, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1816. The method of claim 1790, further comprising producing a mixture from the formation, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1817. The method of claim 1790, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1818. The method of claim 1790, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1819. The method of claim 1790, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1820. The method of claim 1790, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1821. The method of claim 1790, further comprising producing a mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1822. The method of claim 1821, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1823. The method of claim 1790, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1824. The method of claim 1790, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1825. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: heating a first section of the formation to pyrolyze at least some hydrocarbons in the first section and produce a first mixture from the formation; heating a second section of the formation to pyrolyze at least some hydrocarbons in the second section and produce a second mixture from the formation; and leaving an unpyrolyzed section between the first section and the second section to inhibit subsidence of the formation.
 1826. The method of claim 1825, further comprising maintaining a temperature within the first section or the second section within a pyrolysis temperature range.
 1827. The method of claim 1825, wherein heating the first section or heating the second section comprises heating with an electrical heater.
 1828. The method of claim 1825, wherein heating the first section or heating the second section comprises heating with a surface burner.
 1829. The method of claim 1825, wherein heating the first section or heating the second section comprises heating with a flameless distributed combustor.
 1830. The method of claim 1825, wherein heating the first section or heating the second section comprises heating with a natural distributed combustor.
 1831. The method of claim 1825, further comprising controlling a pressure and a temperature within at least a majority of the first or second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1832. The method of claim 1825, further comprising controlling the heat such that an average heating rate of the first or second section is less than about 1° C. per day during pyrolysis.
 1833. The method of claim 1825, wherein heating the first section or heating the second section comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1834. The method of claim 1825, wherein heating the first section or heating the second section comprises transferring heat substantially by conduction.
 1835. The method of claim 1825, wherein the first or second mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1836. The method of claim 1825, wherein the first or second mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1837. The method of claim 1825, wherein the first or second mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1838. The method of claim 1825, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1839. The method of claim 1825, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1840. The method of claim 1825, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1841. The method of claim 1825, wherein the first or second mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1842. The method of claim 1825, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1843. The method of claim 1825, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1844. The method of claim 1825, wherein the first or second mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1845. The method of claim 1825, wherein the first or second mixture comprises a non-condensable component, and wherein the non-condensable component comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1846. The method of claim 1825, wherein the first or second mixture comprises ammonia, and wherein greater than about 0.05% by weight of the first or second mixture is ammonia.
 1847. The method of claim 1825, wherein the first or second mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1848. The method of claim 1825, further comprising controlling a pressure within at least a majority of the first or second section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1849. The method of claim 1825, further comprising controlling formation conditions to produce the first or second mixture, wherein a partial pressure of H₂ within the first or second mixture is greater than about 0.5 bars.
 1850. The method of claim 1825, wherein a partial pressure of H₂ within the first or second mixture is measured when the first or second mixture is at a production well.
 1851. The method of claim 1825, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1852. The method of claim 1825, further comprising controlling formation conditions by recirculating a portion of hydrogen from the first or second mixture into the formation.
 1853. The method of claim 1825, further comprising: providing hydrogen (H₂) to the first or second section to hydrogenate hydrocarbons within the first or second section, respectively; and heating a portion of the first or second section, respectively, with heat from hydrogenation.
 1854. The method of claim 1825, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1855. The method of claim 1825, wherein producing the first or second mixture comprises producing the first or second mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1856. The method of claim 1855, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1857. The method of claim 1825, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1858. The method of claim 1825, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1859. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing a mixture from the formation through one or more production wells, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1860. The method of claim 1859, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1861. The method of claim 1859, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 1862. The method of claim 1859, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 1863. The method of claim 1859, wherein the one or more heat sources comprise electrical heaters.
 1864. The method of claim 1859, wherein the one or more heat sources comprise surface burners.
 1865. The method of claim 1859, wherein the one or more heat sources comprise flameless distributed combustors.
 1866. The method of claim 1859, wherein the one or more heat sources comprise natural distributed combustors.
 1867. The method of claim 1859, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1868. The method of claim 1859, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 1869. The method of claim 1859, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1870. The method of claim 1859, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 1871. The method of claim 1859, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1872. The method of claim 1859, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1873. The method of claim 1859, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1874. The method of claim 1859, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1875. The method of claim 1859, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1876. The method of claim 1859, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1877. The method of claim 1859, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1878. The method of claim 1859, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1879. The method of claim 1859, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1880. The method of claim 1859, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1881. The method of claim 1859, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1882. The method of claim 1859, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1883. The method of claim 1859, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1884. The method of claim 1859, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1885. The method of claim 1859, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1886. The method of claim 1885, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1887. The method of claim 1859, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1888. The method of claim 1859, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1889. The method of claim 1859, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1890. The method of claim 1859, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1891. The method of claim 1859, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1892. The method of claim 1859, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1893. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation, wherein the one or more heat sources are disposed within one or more first wells; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing a mixture from the formation through one or more second wells, wherein one or more of the first or second wells are initially used for a first purpose and are then used for one or more other purposes.
 1894. The method of claim 1893, wherein the first purpose comprises removing water from the formation, and wherein the second purpose comprises providing heat to the formation.
 1895. The method of claim 1893, wherein the first purpose comprises removing water from the formation, and wherein the second purpose comprises producing the mixture.
 1896. The method of claim 1893, wherein the first purpose comprises heating, and wherein the second purpose comprises removing water from the formation.
 1897. The method of claim 1893, wherein the first purpose comprises producing the mixture, and wherein the second purpose comprises removing water from the formation.
 1898. The method of claim 1893, wherein the one or more heat sources comprise electrical heaters.
 1899. The method of claim 1893, wherein the one or more heat sources comprise surface burners.
 1900. The method of claim 1893, wherein the one or more heat sources comprise flameless distributed combustors.
 1901. The method of claim 1893, wherein the one or more heat sources comprise natural distributed combustors.
 1902. The method of claim 1893, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1903. The method of claim 1893, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0° C. per day during pyrolysis.
 1904. The method of claim 1893, wherein providing heat from the one or more heat sources to at least the portion of the formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1905. The method of claim 1893, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1906. The method of claim 1893, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1907. The method of claim 1893, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1908. The method of claim 1893, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1909. The method of claim 1893, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1910. The method of claim 1893, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1911. The method of claim 1893, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1912. The method of claim 1893, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1913. The method of claim 1893, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1914. The method of claim 1893, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1915. The method of claim 1893, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1916. The method of claim 1893, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1917. The method of claim 1893, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1918. The method of claim 1893, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1919. The method of claim 1893, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1920. The method of claim 1919, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 1921. The method of claim 1893, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1922. The method of claim 1893, further comprising controlling formation conditions, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 1923. The method of claim 1893, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 1924. The method of claim 1893, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1925. The method of claim 1893, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1926. The method of claim 1925, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1927. The method of claim 1893, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1928. The method of claim 1893, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1929. A method for forming heater wells in a relatively permeable formation containing heavy hydrocarbons, comprising: forming a first wellbore in the formation; forming a second wellbore in the formation using magnetic tracking such that the second wellbore is arranged substantially parallel to the first wellbore; and providing at least one heat source within the first wellbore and at least one heat source within the second wellbore such that the heat sources can provide heat to at least a portion of the formation.
 1930. The method of claim 1929, wherein superposition of heat from the at least one heat source within the first wellbore and the at least one heat source within the second wellbore pyrolyzes at least some hydrocarbons within a selected section of the formation.
 1931. The method of claim 1929, further comprising maintaining a temperature within a selected section within a pyrolysis temperature range.
 1932. The method of claim 1929, wherein the heat sources comprise electrical heaters.
 1933. The method of claim 1929, wherein the heat sources comprise surface burners.
 1934. The method of claim 1929, wherein the heat sources comprise flameless distributed combustors.
 1935. The method of claim 1929, wherein the heat sources comprise natural distributed combustors.
 1936. The method of claim 1929, further comprising controlling a pressure and a temperature within at least a majority of a selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1937. The method of claim 1929, further comprising controlling the heat from the heat sources such that heat transferred from the heat sources to at least the portion of the hydrocarbons is less than about 1° C. per day during pyrolysis.
 1938. The method of claim 1929, further comprising: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1939. The method of claim 1929, further comprising allowing the heat to transfer from the heat sources to at least the portion of the formation substantially by conduction.
 1940. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1941. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1942. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1943. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1944. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1945. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1946. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1947. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1948. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1949. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1950. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1951. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1952. The method of claim 1929, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1953. The method of claim 1929, further comprising controlling a pressure within at least a majority of a selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1954. The method of claim 1953, wherein the partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1955. The method of claim 1929, further comprising producing a mixture from the formation, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1956. The method of claim 1929, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1957. The method of claim 1929, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1958. The method of claim 1929, further comprising: providing hydrogen (H₂) to the portion to hydrogenate hydrocarbons within the formation; and heating a portion of the formation with heat from hydrogenation.
 1959. The method of claim 1929, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1960. The method of claim 1929, further comprising producing a mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1961. The method of claim 1960, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1962. The method of claim 1929, further comprising forming a production well in the formation using magnetic tracking such that the production well is substantially parallel to the first wellbore and coupling a wellhead to the third wellbore.
 1963. The method of claim 1929, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1964. The method of claim 1929, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 1965. A method for installing a heater well into a relatively permeable formation containing heavy hydrocarbons, comprising: forming a bore in the ground using a steerable motor and an accelerometer; and providing a heat source within the bore such that the heat source can transfer heat to at least a portion of the formation.
 1966. The method of claim 1965, further comprising installing at least two heater wells, and wherein superposition of heat from at least the two heater wells pyrolyzes at least some hydrocarbons within a selected section of the formation.
 1967. The method of claim 1965, further comprising maintaining a temperature within a selected section within a pyrolysis temperature range.
 1968. The method of claim 1965, wherein the heat source comprises an electrical heater.
 1969. The method of claim 1965, wherein the heat source comprises a surface burner.
 1970. The method of claim 1965, wherein the heat source comprises a flameless distributed combustor.
 1971. The method of claim 1965, wherein the heat source comprises a natural distributed combustor.
 1972. The method of claim 1965, further comprising controlling a pressure and a temperature within at least a majority of a selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 1973. The method of claim 1965, further comprising controlling the heat from the heat source such that heat transferred from the heat source to at least the portion of the formation is less than about 1° C. per day during pyrolysis.
 1974. The method of claim 1965, further comprising: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the heat source, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 1975. The method of claim 1965, further comprising allowing the heat to transfer from the heat source to at least the portion of the formation substantially by conduction.
 1976. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 1977. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 1978. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 1979. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 1980. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 1981. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 1982. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 1983. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 1984. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 1985. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 1986. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 1987. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 1988. The method of claim 1965, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 1989. The method of claim 1965, further comprising controlling a pressure within at least a majority of a selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 1990. The method of claim 1965, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 1991. The method of claim 1990, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 1992. The method of claim 1965, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 1993. The method of claim 1965, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 1994. The method of claim 1965, further comprising: providing hydrogen (H₂) to the at least the heated portion to hydrogenate hydrocarbons within the formation; and heating a portion of the formation with heat from hydrogenation.
 1995. The method of claim 1965, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 1996. The method of claim 1965, further comprising producing a mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 1997. The method of claim 1996, wherein at least about 20 heat sources are disposed in the formation for each production well.
 1998. The method of claim 1965, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 1999. The method of claim 1965, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 2000. A method for installing of wells in a relatively permeable formation containing heavy hydrocarbons, comprising: forming a wellbore in the formation by geosteered drilling; and providing a heat source within the wellbore such that the heat source can transfer heat to at least a portion of the formation.
 2001. The method of claim 2000, further comprising maintaining a temperature within a selected section within a pyrolysis temperature range.
 2002. The method of claim 2000, wherein the heat source comprises an electrical heater.
 2003. The method of claim 2000, wherein the heat source comprises a surface burner.
 2004. The method of claim 2000, wherein the heat source comprises a flameless distributed combustor.
 2005. The method of claim 2000, wherein the heat source comprises a natural distributed combustor.
 2006. The method of claim 2000, further comprising controlling a pressure and a temperature within at least a majority of a selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 2007. The method of claim 2000, further comprising controlling the heat from the heat source such that heat transferred from the heat source to at least the portion of the formation is less than about 1° C. per day during pyrolysis.
 2008. The method of claim 2000, further comprising: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the heat source, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 2009. The method of claim 2000, further comprising allowing the heat to transfer from the heat source to at least the portion of the formation substantially by conduction.
 2010. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 2011. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 2012. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 2013. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 2014. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 2015. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 2016. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 2017. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 2018. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 2019. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 2020. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 2021. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 2022. The method of claim 2000, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 2023. The method of claim 2000, further comprising controlling a pressure within at least a majority of a selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 2024. The method of claim 2000, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 2025. The method of claim 2024, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 2026. The method of claim 2000, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 2027. The method of claim 2000, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 2028. The method of claim 2000, further comprising: providing hydrogen (H₂) to at least the heated portion to hydrogenate hydrocarbons within the formation; and heating a portion of the formation with heat from hydrogenation.
 2029. The method of claim 2000, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 2030. The method of claim 2000, further comprising producing a mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 2031. The method of claim 2030, wherein at least about 20 heat sources are disposed in the formation for each production well.
 2032. The method of claim 2000, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 2033. The method of claim 2000, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 2034. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: heating a selected section of the formation with a heating element placed within a wellbore, wherein at least one end of the heating element is free to move axially within the wellbore to allow for thermal expansion of the heating element.
 2035. The method of claim 2034, further comprising at least two heating elements within at least two wellbores, and wherein superposition of heat from at least the two heating elements pyrolyzes at least some hydrocarbons within a selected section of the formation.
 2036. The method of claim 2034, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 2037. The method of claim 2034, wherein the heating element comprises a pipe-in-pipe heater.
 2038. The method of claim 2034, wherein the heating element comprises a flameless distributed combustor.
 2039. The method of claim 2034, wherein the heating element comprises a mineral insulated cable coupled to a support, and wherein the support is free to move within the wellbore.
 2040. The method of claim 2034, wherein the heating element comprises a mineral insulated cable suspended from a wellhead.
 2041. The method of claim 2034, further comprising controlling a pressure and a temperature within at least a majority of a heated section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 2042. The method of claim 2034, further comprising controlling the heat such that an average heating rate of the heated section is less than about 1° C. per day during pyrolysis.
 2043. The method of claim 2034, wherein heating the section of the formation further comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the heating element, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 2044. The method of claim 2034, wherein heating the section of the formation comprises transferring heat substantially by conduction.
 2045. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 2046. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 2047. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 2048. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons; and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 2049. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 2050. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 2051. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 2052. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 2053. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 2054. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 2055. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 2056. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 2057. The method of claim 2034, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 2058. The method of claim 2034, further comprising controlling a pressure within the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 2059. The method of claim 2034, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 2060. The method of claim 2059, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 2061. The method of claim 2034, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 2062. The method of claim 2034, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 2063. The method of claim 2034, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the heated section; and heating a portion of the section with heat from hydrogenation.
 2064. The method of claim 2034, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 2065. The method of claim 2034, further comprising producing a mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 2066. The method of claim 2065, wherein at least about 20 heat sources are disposed in the formation for each production well.
 2067. The method of claim 2034, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 2068. The method of claim 2034, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 2069. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing a mixture from the formation through a production well, wherein the production well is located such that a majority of the mixture produced from the formation comprises non-condensable hydrocarbons and a non-condensable component comprising hydrogen.
 2070. The method of claim 2069, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 2071. The method of claim 2069, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 2072. The method of claim 2069, wherein the production well is less than approximately 6 m from a heat source of the one or more heat sources.
 2073. The method of claim 2069, wherein the production well is less than approximately 3 m from a heat source of the one or more heat sources.
 2074. The method of claim 2069, wherein the production well is less than approximately 1.5 m from a heat source of the one or more heat sources.
 2075. The method of claim 2069, wherein an additional heat source is positioned within a wellbore of the production well.
 2076. The method of claim 2069, wherein the one or more heat sources comprise electrical heaters.
 2077. The method of claim 2069, wherein the one or more heat sources comprise surface burners.
 2078. The method of claim 2069, wherein the one or more heat sources comprise flameless distributed combustors.
 2079. The method of claim 2069, wherein the one or more heat sources comprise natural distributed combustors.
 2080. The method of claim 2069, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 2081. The method of claim 2069, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 2082. The method of claim 2069, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 2083. The method of claim 2069, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.
 2084. The method of claim 2069, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 2085. The method of claim 2069, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 2086. The method of claim 2069, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 2087. The method of claim 2069, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 2088. The method of claim 2069, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 2089. The method of claim 2069, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 2090. The method of claim 2069, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 2091. The method of claim 2069, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 2092. The method of claim 2069, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 2093. The method of claim 2069, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 2094. The method of claim 2069, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 2095. The method of claim 2069, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 2096. The method of claim 2069, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 2097. The method of claim 2069, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 2098. The method of claim 2069, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 2099. The method of claim 2098, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 2100. The method of claim 2069, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 2101. The method of claim 2069, further comprising controlling formation conditions by recirculating a portion of the hydrogen from the mixture into the formation.
 2102. The method of claim 2069, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 2103. The method of claim 2069, further comprising: producing condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 2104. The method of claim 2069, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 2105. The method of claim 2104, wherein at least about 20 heat sources are disposed in the formation for each production well.
 2106. The method of claim 2069, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 2107. The method of claim 2069, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 2108. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat to at least a portion of the formation from one or more first heat sources placed within a pattern in the formation; allowing the heat to transfer from the one or more first heat sources to a first section of the formation; heating a second section of the formation with at least one second heat source, wherein the second section is located within the first section, and wherein at least the one second heat source is configured to raise an average temperature of a portion of the second section to a higher temperature than an average temperature of the first section; and producing a mixture from the formation through a production well positioned within the second section, wherein a majority of the produced mixture comprises non-condensable hydrocarbons and a non-condensable component comprising H₂ components.
 2109. The method of claim 2108, wherein the one or more first heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the first section of the formation.
 2110. The method of claim 2108, further comprising maintaining a temperature within the first section within a pyrolysis temperature range.
 2111. The method of claim 2108, wherein at least the one heat source comprises a heater element positioned within the production well.
 2112. The method of claim 2108, wherein at least the one second heat source comprises an electrical heater.
 2113. The method of claim 2108, wherein at least the one second heat source comprises a surface burner.
 2114. The method of claim 2108, wherein at least the one second heat source comprises a flameless distributed combustor.
 2115. The method of claim 2108, wherein at least the one second heat source comprises a natural distributed combustor.
 2116. The method of claim 2108, further comprising controlling a pressure and a temperature within at least a majority of the first or the second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 2117. The method of claim 2108, further comprising controlling the heat such that an average heating rate of the first section is less than about 1° C. per day during pyrolysis.
 2118. The method of claim 2108, wherein providing heat to the formation further comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more first heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 2119. The method of claim 2108, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 2120. The method of claim 2108, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 2121. The method of claim 2108, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 2122. The method of claim 2108, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 2123. The method of claim 2108, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 2124. The method of claim 2108, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 2125. The method of claim 2108, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 2126. The method of claim 2108, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 2127. The method of claim 2108, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 2128. The method of claim 2108, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 2129. The method of claim 2108, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 2130. The method of claim 2108, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 2131. The method of claim 2108, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 2132. The method of claim 2108, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 2133. The method of claim 2108, further comprising controlling a pressure within at least a majority of the first or the second section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 2134. The method of claim 2108, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 2135. The method of claim 2134, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 2136. The method of claim 2108, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 2137. The method of claim 2108, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 2138. The method of claim 2108, further comprising: providing hydrogen (H₂) to the first or second section to hydrogenate hydrocarbons within the first or second section, respectively; and heating a portion of the first or second section, respectively, with heat from hydrogenation.
 2139. The method of claim 2108, further comprising: producing condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 2140. The method of claim 2108, wherein at least about 7 heat sources are disposed in the formation for each production well.
 2141. The method of claim 2140, wherein at least about 20 heat sources are disposed in the formation for each production well.
 2142. The method of claim 2108, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 2143. The method of claim 2108, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 2144. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat into the formation from a plurality of heat sources placed in a pattern within the formation, wherein a spacing between heat sources is greater than about 6 m; allowing the heat to transfer from the plurality of heat sources to a selected section of the formation; producing a mixture from the formation from a plurality of production wells, wherein the plurality of production wells are positioned within the pattern, and wherein a spacing between production wells is greater than about 12 m.
 2145. The method of claim 2144, wherein superposition of heat from the plurality of heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 2146. The method of claim 2144, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.
 2147. The method of claim 2144, wherein the plurality of heat sources comprises electrical heaters.
 2148. The method of claim 2144, wherein the plurality of heat sources comprises surface burners.
 2149. The method of claim 2144, wherein the plurality of heat sources comprises flameless distributed combustors.
 2150. The method of claim 2144, wherein the plurality of heat sources comprises natural distributed combustors.
 2151. The method of claim 2144, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 2152. The method of claim 2144, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 2153. The method of claim 2144, wherein providing heat from the plurality of heat sources comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the plurality of heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 2154. The method of claim 2144, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.
 2155. The method of claim 2144, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 2156. The method of claim 2144, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 2157. The method of claim 2144, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 2158. The method of claim 2144, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 2159. The method of claim 2144, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 2160. The method of claim 2144, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 2161. The method of claim 2144, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 2162. The method of claim 2144, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 2163. The method of claim 2144, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 2164. The method of claim 2144, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 2165. The method of claim 2144, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 2166. The method of claim 2144, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 2167. The method of claim 2144, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 2168. The method of claim 2144, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 2169. The method of claim 2144, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.
 2170. The method of claim 2169, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.
 2171. The method of claim 2144, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 2172. The method of claim 2144, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 2173. The method of claim 2144, further comprising: providing hydrogen (H₂) to the selected section to hydrogenate hydrocarbons within the selected section; and heating a portion of the selected section with heat from hydrogenation.
 2174. The method of claim 2144, further comprising: producing hydrogen and condensable hydrocarbons from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 2175. The method of claim 2144, wherein at least about 7 heat sources are disposed in the formation for each production well.
 2176. The method of claim 2175, wherein at least about 20 heat sources are disposed in the formation for each production well.
 2177. The method of claim 2144, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 2178. The method of claim 2144, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 2179. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a heater disposed in an opening in the formation, wherein the heater is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2180. The system of claim 2179, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2181. The system of claim 2179, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.
 2182. The system of claim 2179, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2183. The system of claim 2179, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2184. The system of claim 2179, wherein the conduit is further configured to remove an oxidation product.
 2185. The system of claim 2179, wherein the conduit is further configured to remove an oxidation product such that the oxidation product transfers substantial heat to the oxidizing fluid.
 2186. The system of claim 2179, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2187. The system of claim 2179, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2188. The system of claim 2179, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2189. The system of claim 2179, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2190. The system of claim 2179, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.
 2191. The system of claim 2179, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2192. The system of claim 2179, further comprising a conductor disposed in a second conduit, wherein the second conduit is disposed within the opening, and wherein the conductor is configured to heat at least a portion of the formation during application of an electrical current to the conductor.
 2193. The system of claim 2179, further comprising an insulated conductor disposed within the opening, wherein the insulated conductor is configured to heat at least a portion of the formation during application of an electrical current to the insulated conductor.
 2194. The system of claim 2179, further comprising at least one elongated member disposed within the opening, wherein the at least the one elongated member is configured to heat at least a portion of the formation during application of an electrical current to the at least the one elongated member.
 2195. The system of claim 2179, further comprising a heat exchanger disposed external to the formation, wherein the heat exchanger is configured to heat the oxidizing fluid, wherein the conduit is further configured to provide the heated oxidizing fluid into the opening during use, and wherein the heated oxidizing fluid is configured to heat at least a portion of the formation during use.
 2196. The system of claim 2179, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2197. The system of claim 2179, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2198. The system of claim 2179, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2199. The system of claim 2179, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2200. The system of claim 2179, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2201. The system of claim 2179, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2202. The system of claim 2179, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2203. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a heater configurable to be disposed in an opening in the formation, wherein the heater is further configurable to provide heat to at least a portion of the formation during use; a conduit configurable to be disposed in the opening, wherein the conduit is configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2204. The system of claim 2203, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2205. The system of claim 2203, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.
 2206. The system of claim 2203, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2207. The system of claim 2203, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2208. The system of claim 2203, wherein the conduit is further configurable to remove an oxidation product.
 2209. The system of claim 2203, wherein the conduit is further configurable to remove an oxidation product, such that the oxidation product transfers heat to the oxidizing fluid.
 2210. The system of claim 2203, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2211. The system of claim 2203, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2212. The system of claim 2203, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2213. The system of claim 2203, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2214. The system of claim 2203, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configurable to remove an oxidation product during use.
 2215. The system of claim 2203, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2216. The system of claim 2203, further comprising a conductor disposed in a second conduit, wherein the second conduit is disposed within the opening, and wherein the conductor is configurable to heat at least a portion of the formation during application of an electrical current to the conductor.
 2217. The system of claim 2203, further comprising an insulated conductor disposed within the opening, wherein the insulated conductor is configurable to heat at least a portion of the formation during application of an electrical current to the insulated conductor.
 2218. The system of claim 2203, further comprising at least one elongated member disposed within the opening, wherein the at least the one elongated member is configurable to heat at least a portion of the formation during application of an electrical current to the at least the one elongated member.
 2219. The system of claim 2203, further comprising a heat exchanger disposed external to the formation, wherein the heat exchanger is configurable to heat the oxidizing fluid, wherein the conduit is further configurable to provide the heated oxidizing fluid into the opening during use, and wherein the heated oxidizing fluid is configurable to heat at least a portion of the formation during use.
 2220. The system of claim 2203, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2221. The system of claim 2203, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2222. The system of claim 2203, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2223. The system of claim 2203, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2224. The system of claim 2203, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2225. The system of claim 2203, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2226. The system of claim 2203, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2227. The system of claim 2203, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: a heater disposed in an opening in the formation, wherein the heater is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2228. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.
 2229. The method of claim 2228, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.
 2230. The method of claim 2228, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.
 2231. The method of claim 2228, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.
 2232. The method of claim 2228, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.
 2233. The method of claim 2228, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.
 2234. The method of claim 2228, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.
 2235. The method of claim 2228, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to oxidizing fluid in the conduit.
 2236. The method of claim 2228, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2237. The method of claim 2228, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.
 2238. The method of claim 2228, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.
 2239. The method of claim 2228, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.
 2240. The method of claim 2228, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.
 2241. The method of claim 2228, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2242. The method of claim 2228, wherein heating the portion comprises applying electrical current to a conductor disposed in a conduit, wherein the conduit is disposed within the opening.
 2243. The method of claim 2228, wherein heating the portion comprises applying electrical current to an insulated conductor disposed within the opening.
 2244. The method of claim 2228, wherein heating the portion comprises applying electrical current to at least one elongated member disposed within the opening.
 2245. The method of claim 2228, wherein heating the portion comprises heating the oxidizing fluid in a heat exchanger disposed external to the formation such that providing the oxidizing fluid into the opening comprises transferring heat from the heated oxidizing fluid to the portion.
 2246. The method of claim 2228, further comprising removing water from the formation prior to heating the portion.
 2247. The method of claim 2228, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.
 2248. The method of claim 2228, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2249. The method of claim 2228, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2250. The method of claim 2228, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2251. The method of claim 2228, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2252. The method of claim 2228, wherein the pyrolysis zone is substantially adjacent to the reaction zone.
 2253. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a heater disposed in an opening in the formation, wherein the heater is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone, and wherein the conduit is further configured to remove an oxidation product from the formation during use; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2254. The system of claim 2253, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2255. The system of claim 2253, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.
 2256. The system of claim 2253, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2257. The system of claim 2253, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2258. The system of claim 2253, wherein the conduit is further configured such that the oxidation product transfers heat to the oxidizing fluid.
 2259. The system of claim 2253, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2260. The system of claim 2253, wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2261. The system of claim 2253, wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2262. The system of claim 2253, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2263. The system of claim 2253, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use.
 2264. The system of claim 2253, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2265. The system of claim 2253, further comprising a conductor disposed in a second conduit, wherein the second conduit is disposed within the opening, and wherein the conductor is configured to heat at least a portion of the formation during application of an electrical current to the conductor.
 2266. The system of claim 2253, further comprising an insulated conductor disposed within the opening, wherein the insulated conductor is configured to heat at least a portion of the formation during application of an electrical current to the insulated conductor.
 2267. The system of claim 2253, further comprising at least one elongated member disposed within the opening, wherein the at least the one elongated member is configured to heat at least a portion of the formation during application of an electrical current to the at least the one elongated member.
 2268. The system of claim 2253, further comprising a heat exchanger disposed external to the formation, wherein the heat exchanger is configured to heat the oxidizing fluid, wherein the conduit is further configured to provide the heated oxidizing fluid into the opening during use, and wherein the heated oxidizing fluid is configured to heat at least a portion of the formation during use.
 2269. The system of claim 2253, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2270. The system of claim 2253, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2271. The system of claim 2253, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2272. The system of claim 2253, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2273. The system of claim 2253, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2274. The system of claim 2253, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2275. The system of claim 2253, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2276. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a heater configurable to be disposed in an opening in the formation, wherein the heater is further configurable to provide heat to at least a portion of the formation during use; a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone, and wherein the conduit is further configurable to remove an oxidation product from the formation during use; and wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone during use.
 2277. The system of claim 2276, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2278. The system of claim 2276, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.
 2279. The system of claim 2276, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2280. The system of claim 2276, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2281. The system of claim 2276, wherein the conduit is further configurable such that the oxidation product transfers heat to the oxidizing fluid.
 2282. The system of claim 2276, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2283. The system of claim 2276, wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2284. The system of claim 2276, wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2285. The system of claim 2276, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2286. The system of claim 2276, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use.
 2287. The system of claim 2276, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2288. The system of claim 2276, further comprising a conductor disposed in a second conduit, wherein the second conduit is disposed within the opening, and wherein the conductor is configurable to heat at least a portion of the formation during application of an electrical current to the conductor.
 2289. The system of claim 2276, further comprising an insulated conductor disposed within the opening, wherein the insulated conductor is configurable to heat at least a portion of the formation during application of an electrical current to the insulated conductor.
 2290. The system of claim 2276, further comprising at least one elongated member disposed within the opening, wherein the at least the one elongated member is configurable to heat at least a portion of the formation during application of an electrical current to the at least the one elongated member.
 2291. The system of claim 2276, further comprising a heat exchanger disposed external to the formation, wherein the heat exchanger is configurable to heat the oxidizing fluid, wherein the conduit is further configurable to provide the heated oxidizing fluid into the opening during use, and wherein the heated oxidizing fluid is configurable to heat at least a portion of the formation during use.
 2292. The system of claim 2276, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2293. The system of claim 2276, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2294. The system of claim 2276, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2295. The system of claim 2276, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2296. The system of claim 2276, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2297. The system of claim 2276, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2298. The system of claim 2276, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2299. The system of claim 2276, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: a heater disposed in an opening in the formation, wherein the heater is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an to oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone, and wherein the conduit is further configured to remove an oxidation product from the formation during use; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2300. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein the portion is located substantially adjacent to an opening in the formation; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing gas to react with at least a portion of the hydrocarbons at the reaction zone to generate heat in the reaction zone; removing at least a portion of an oxidation product through the opening; and transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.
 2301. The method of claim 2300, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.
 2302. The method of claim 2300, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.
 2303. The method of claim 2300, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.
 2304. The method of claim 2300, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially maintained within the reaction zone.
 2305. The method of claim 2300, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2306. The method of claim 2300, wherein a conduit is disposed within the opening, and wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit.
 2307. The method of claim 2300, wherein a conduit is disposed within the opening, and wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit, the method further comprising transferring substantial heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.
 2308. The method of claim 2300, wherein a conduit is disposed within the opening, wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2309. The method of claim 2300, wherein a conduit is disposed within the opening, and wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit, the method further comprising controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.
 2310. The method of claim 2300, wherein a conduit is disposed within the opening, and wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit, the method further comprising substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.
 2311. The method of claim 2300, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.
 2312. The method of claim 2300, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing at least a portion of the oxidation product through the outer conduit.
 2313. The method of claim 2300, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2314. The method of claim 2300, wherein heating the portion comprises applying electrical current to a conductor disposed in a conduit, wherein the conduit is disposed within the opening.
 2315. The method of claim 2300, wherein heating the portion comprises applying electrical current to an insulated conductor disposed within the opening.
 2316. The method of claim 2300, wherein heating the portion comprises applying electrical current to at least one elongated member disposed within the opening.
 2317. The method of claim 2300, wherein heating the portion comprises heating the oxidizing fluid in a heat exchanger disposed external to the formation such that providing the oxidizing fluid into the opening comprises transferring heat from the heated oxidizing fluid to the portion.
 2318. The method of claim 2300, further comprising removing water from the formation prior to heating the portion.
 2319. The method of claim 2300, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.
 2320. The method of claim 2300, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2321. The method of claim 2300, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2322. The method of claim 2300, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2323. The method of claim 2300, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a function of the overburden casing and the opening.
 2324. The method of claim 2300, wherein the pyrolysis zone is substantially adjacent to the reaction.
 2325. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: an electric heater disposed in an opening in the formation, wherein the electric heater is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2326. The system of claim 2325, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2327. The system of claim 2325, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.
 2328. The system of claim 2325, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2329. The system of claim 2325, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2330. The system of claim 2325, wherein the conduit is further configured to remove an oxidation product.
 2331. The system of claim 2325, wherein the conduit is further configured to remove an oxidation product, such that the oxidation product transfers heat to the oxidizing fluid.
 2332. The system of claim 2325, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2333. The system of claim 2325, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2334. The system of claim 2325, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2335. The system of claim 2325, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2336. The system of claim 2325, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.
 2337. The system of claim 2325, wherein the portion of the formation extends radially from the opening a width of Less than approximately 0.2 m.
 2338. The system of claim 2325, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2339. The system of claim 2325, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2340. The system of claim 2325, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2341. The system of claim 2325, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2342. The system of claim 2325, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2343. The system of claim 2325, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2344. The system of claim 2325, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2345. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: an electric heater configurable to be disposed in an opening in the formation, wherein the electric heater is further configurable to provide heat to at least a portion of the formation during use, and wherein at least the portion is located substantially adjacent to the opening; a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2346. The system of claim 2345, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2347. The system of claim 2345, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.
 2348. The system of claim 2345, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2349. The system of claim 2345, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2350. The system of claim 2345, wherein the conduit is further configurable to remove an oxidation product.
 2351. The system of claim 2345, wherein the conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.
 2352. The system of claim 2345, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2353. The system of claim 2345, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2354. The system of claim 2345, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2355. The system of claim 2345, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2356. The system of claim 2345, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configurable to remove an oxidation product during use.
 2357. The system of claim 2345, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2358. The system of claim 2345, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2359. The system of claim 2345, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2360. The system of claim 2345, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2361. The system of claim 2345, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2362. The system of claim 2345, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2363. The system of claim 2345, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2364. The system of claim 2345, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2365. The system of claim 2345, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: an electric heater disposed in an opening in the formation, wherein the electric heater is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2366. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a conductor disposed in a first conduit, wherein the first conduit is disposed in an opening in the formation, and wherein the conductor is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a second conduit disposed in the opening, wherein the second conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2367. The system of claim 2366, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2368. The system of claim 2366, wherein the second conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.
 2369. The system of claim 2366, wherein the second conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2370. The system of claim 2366, wherein the second conduit is further configured to be cooled with the oxidizing fluid to reduce heating of the second conduit by oxidation.
 2371. The system of claim 2366, wherein the second conduit is further configured to remove an oxidation product.
 2372. The system of claim 2366, wherein the second conduit is further configured to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.
 2373. The system of claim 2366, wherein the second conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the second conduit.
 2374. The system of claim 2366, wherein the second conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the second conduit and a pressure of the oxidation product in the second conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2375. The system of claim 2366, wherein the second conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2376. The system of claim 2366, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2377. The system of claim 2366, further comprising a center conduit disposed within the second conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the second conduit is further configured to remove an oxidation product during use.
 2378. The system of claim 2366, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2379. The system of claim 2366, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2380. The system of claim 2366, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2381. The system of claim 2366, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2382. The system of claim 2366, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2383. The system of claim 2366, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2384. The system of claim 2366, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2385. The system of claim 2366, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2386. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a conductor configurable to be disposed in a first conduit, wherein the first conduit is configurable to be disposed in an opening in the formation, and wherein the conductor is further configurable to provide heat to at least a portion of the formation during use; a second conduit configurable to be disposed in the opening, wherein the second conduit is further configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2387. The system of claim 2386, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2388. The system of claim 2386, wherein the second conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.
 2389. The system of claim 2386, wherein the second conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2390. The system of claim 2386, wherein the second conduit is further configurable to be cooled with the oxidizing fluid to reduce heating of the second conduit by oxidation.
 2391. The system of claim 2386, wherein the second conduit is further configurable to remove an oxidation product.
 2392. The system of claim 2386, wherein the second conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.
 2393. The system of claim 2386, wherein the second conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the second conduit.
 2394. The system of claim 2386, wherein the second conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the second conduit and a pressure of the oxidation product in the second conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2395. The system of claim 2386, wherein the second conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2396. The system of claim 2386, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2397. The system of claim 2386, further comprising a center conduit disposed within the second conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the second conduit is further configurable to remove an oxidation product during use.
 2398. The system of claim 2386, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2399. The system of claim 2386, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2400. The system of claim 2386, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2401. The system of claim 2386, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2402. The system of claim 2386, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2403. The system of claim 2386, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2404. The system of claim 2386, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2405. The system of claim 2386, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2406. The system of claim 2386, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: a conductor disposed in a first conduit, wherein the first conduit is disposed in an opening in the formation, and wherein the conductor is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a second conduit disposed in the opening, wherein the second conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2407. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises applying an electrical current to a conductor disposed in a first conduit to provide heat to the portion, and wherein the first conduit is disposed within the opening; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.
 2408. The method of claim 2407, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.
 2409. The method of claim 2407, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a second conduit disposed in the opening.
 2410. The method of claim 2407, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a second conduit disposed in the opening such that a rate of oxidation is controlled.
 2411. The method of claim 2407, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.
 2412. The method of claim 2407, wherein a second conduit is disposed in the opening, the method further comprising cooling the second conduit with the oxidizing fluid to reduce heating of the second conduit by oxidation.
 2413. The method of claim 2407, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the second conduit.
 2414. The method of claim 2407, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the second conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the second conduit.
 2415. The method of claim 2407, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the second conduit, wherein a flow rate of the oxidizing fluid in the second conduit is approximately equal to a flow rate of the oxidation product in the second conduit.
 2416. The method of claim 2407, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the second conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the second conduit to reduce contamination of the oxidation product by the oxidizing fluid.
 2417. The method of claim 2407, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.
 2418. The method of claim 2407, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.
 2419. The method of claim 2407, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.
 2420. The method of claim 2407, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2421. The method of claim 2407, further comprising removing water from the formation prior to heating the portion.
 2422. The method of claim 2407, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.
 2423. The method of claim 2407, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2424. The method of claim 2407, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2425. The method of claim 2407, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2426. The method of claim 2407, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2427. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: an insulated conductor disposed in an opening in the formation, wherein the insulated conductor is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2428. The system of claim 2427, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2429. The system of claim 2427, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.
 2430. The system of claim 2427, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2431. The system of claim 2427, wherein the conduit is configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2432. The system of claim 2427, wherein the conduit is further configured to remove an oxidation product.
 2433. The system of claim 2427, wherein the conduit is further configured to remove an oxidation product, and wherein the conduit is further configured such that the oxidation product transfers substantial heat to the oxidizing fluid.
 2434. The system of claim 2427, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2435. The system of claim 2427, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the second conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2436. The system of claim 2427, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2437. The system of claim 2427, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2438. The system of claim 2427, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.
 2439. The system of claim 2427, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2440. The system of claim 2427, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2441. The system of claim 2427, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2442. The system of claim 2427, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2443. The system of claim 2427, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2444. The system of claim 2427, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2445. The system of claim 2427, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2446. The system of claim 2427, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2447. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: an insulated conductor configurable to be disposed in an opening in the formation, wherein the insulated conductor is further configurable to provide heat to at least a portion of the formation during use; a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2448. The system of claim 2447, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2449. The system of claim 2447, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.
 2450. The system of claim 2447, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2451. The system of claim 2447, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2452. The system of claim 2447, wherein the conduit is further configurable to remove an oxidation product.
 2453. The system of claim 2447, wherein the conduit is further configurable to remove an oxidation product, such that the oxidation product transfers heat to the oxidizing fluid.
 2454. The system of claim 2447, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2455. The system of claim 2447, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2456. The system of claim 2447, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2457. The system of claim 2447, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2458. The system of claim 2447, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configurable to remove an oxidation product during use.
 2459. The system of claim 2447, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2460. The system of claim 2447, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2461. The system of claim 2447, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2462. The system of claim 2447, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2463. The system of claim 2447, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2464. The system of claim 2447, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2465. The system of claim 2447, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2466. The system of claim 2447, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2467. The system of claim 2447, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: an insulated conductor disposed in an opening in the formation, wherein the insulated conductor is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2468. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises applying an electrical current to an insulated conductor to provide heat to the portion, and wherein the insulated conductor is disposed within the opening; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.
 2469. The method of claim 2468, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.
 2470. The method of claim 2468, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.
 2471. The method of claim 2468, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.
 2472. The method of claim 2468, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.
 2473. The method of claim 2468, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.
 2474. The method of claim 2468, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.
 2475. The method of claim 2468, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.
 2476. The method of claim 2468, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2477. The method of claim 2468, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.
 2478. The method of claim 2468, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.
 2479. The method of claim 2468, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.
 2480. The method of claim 2468, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.
 2481. The method of claim 2468, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2482. The method of claim 2468, further comprising removing water from the formation prior to heating the portion.
 2483. The method of claim 2468, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.
 2484. The method of claim 2468, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2485. The method of claim 2468, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2486. The method of claim 2468, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2487. The method of claim 2468, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2488. The method of claim 2468, wherein the pyrolysis zone is substantially adjacent to the reaction zone.
 2489. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein the portion is located substantially adjacent to an opening in the formation, wherein heating comprises applying an electrical current to an insulated conductor to provide heat to the portion, wherein the insulated conductor is coupled to a conduit, wherein the conduit comprises critical flow orifices, and wherein the conduit is disposed within the opening; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.
 2490. The method of claim 2489, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.
 2491. The method of claim 2489, further comprising controlling a flow of the oxidizing fluid with the critical flow orifices such that a rate of oxidation is controlled.
 2492. The method of claim 2489, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.
 2493. The method of claim 2489, further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.
 2494. The method of claim 2489, further comprising removing an oxidation product from the formation through the conduit.
 2495. The method of claim 2489, further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.
 2496. The method of claim 2489, further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2497. The method of claim 2489, further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.
 2498. The method of claim 2489, further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.
 2499. The method of claim 2489, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.
 2500. The method of claim 2489, wherein a center conduit is disposed within the conduit, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the conduit.
 2501. The method of claim 2489, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2502. The method of claim 2489, further comprising removing water from the formation prior to heating the portion.
 2503. The method of claim 2489, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.
 2504. The method of claim 2489, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2505. The method of claim 2489, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2506. The method of claim 2489, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2507. The method of claim 2489, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2508. The method of claim 2489, wherein the pyrolysis zone is substantially adjacent to the reaction zone.
 2509. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least one elongated member disposed in an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2510. The system of claim 2509, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2511. The system of claim 2509, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.
 2512. The system of claim 2509, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2513. The system of claim 2509, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2514. The system of claim 2509, wherein the conduit is further configured to remove an oxidation product.
 2515. The system of claim 2509, wherein the conduit is further configured to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.
 2516. The system of claim 2509, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2517. The system of claim 2509, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2518. The system of claim 2509, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2519. The system of claim 2509, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2520. The system of claim 2509, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.
 2521. The system of claim 2509, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2522. The system of claim 2509, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2523. The system of claim 2509, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2524. The system of claim 2509, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2525. The system of claim 2509, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2526. The system of claim 2509, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2527. The system of claim 2509, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2528. The system of claim 2509, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2529. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least one elongated member configurable to be disposed in an opening in the formation, wherein at least the one elongated member is further configurable to provide heat to at least a portion of the formation during use; a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2530. The system of claim 2529, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2531. The system of claim 2529, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.
 2532. The system of claim 2529, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2533. The system of claim 2529, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2534. The system of claim 2529, wherein the conduit is further configurable to remove an oxidation product.
 2535. The system of claim 2529, wherein the conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.
 2536. The system of claim 2529, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2537. The system of claim 2529, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2538. The system of claim 2529, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2539. The system of claim 2529, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2540. The system of claim 2529, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configurable to remove an oxidation product during use.
 2541. The system of claim 2529, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2542. The system of claim 2529, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2543. The system of claim 2529, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2544. The system of claim 2529, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2545. The system of claim 2529, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2546. The system of claim 2529, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2547. The system of claim 2529, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2548. The system of claim 2529, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 2549. The system of claim 2529, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: at least one elongated member disposed in an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2550. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises applying an electrical current to at least one elongated member to provide heat to the portion, and wherein at least the one elongated member is disposed within the opening; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.
 2551. The method of claim 2550, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.
 2552. The method of claim 2550, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.
 2553. The method of claim 2550, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.
 2554. The method of claim 2550, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.
 2555. The method of claim 2550, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.
 2556. The method of claim 2550, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.
 2557. The method of claim 2550, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.
 2558. The method of claim 2550, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2559. The method of claim 2550, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.
 2560. The method of claim 2550, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.
 2561. The method of claim 2550, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.
 2562. The method of claim 2550, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.
 2563. The method of claim 2550, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2564. The method of claim 2550, further comprising removing water from the formation prior to heating the portion.
 2565. The method of claim 2550, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.
 2566. The method of claim 2550, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2567. The method of claim 2550, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2568. The method of claim 2550, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2569. The method of claim 2550, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2570. The method of claim 2550, wherein the pyrolysis zone is substantially adjacent to the reaction zone.
 2571. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a heat exchanger disposed external to the formation, wherein the heat exchanger is configured to heat an oxidizing fluid during use; a conduit disposed in the opening, wherein the conduit is configured to provide the heated oxidizing fluid from the heat exchanger to at least a portion of the formation during use, wherein the system is configured to allow heat to transfer from the heated oxidizing fluid to at least the portion of the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at a reaction zone in the formation during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2572. The system of claim 2571, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2573. The system of claim 2571, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.
 2574. The system of claim 2571, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2575. The system of claim 2571, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2576. The system of claim 2571, wherein the conduit is further configured to remove an oxidation product.
 2577. The system of claim 2571, wherein the conduit is further configured to remove an oxidation product, such that the oxidation product transfers heat to the oxidizing fluid.
 2578. The system of claim 2571, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2579. The system of claim 2571, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2580. The system of claim 2571, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2581. The system of claim 2571, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2582. The system of claim 2571, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.
 2583. The system of claim 2571, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2584. The system of claim 2571, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2585. The system of claim 2571, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2586. The system of claim 2571, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2587. The system of claim 2571, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2588. The system of claim 2571, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2589. The system of claim 2571, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2590. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a heat exchanger configurable to be disposed external to the formation, wherein the heat exchanger is further configurable to heat an oxidizing fluid during use; a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide the heated oxidizing fluid from the heat exchanger to at least a portion of the formation during use, wherein the system is configurable to allow heat to transfer from the heated oxidizing fluid to at least the portion of the formation during use, and wherein the system is further configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at a reaction zone in the formation during use such that heat is generated at the reaction zone; and wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2591. The system of claim 2590, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 2592. The system of claim 2590, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.
 2593. The system of claim 2590, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.
 2594. The system of claim 2590, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.
 2595. The system of claim 2590, wherein the conduit is further configurable to remove an oxidation product.
 2596. The system of claim 2590, wherein the conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.
 2597. The system of claim 2590, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2598. The system of claim 2590, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.
 2599. The system of claim 2590, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2600. The system of claim 2590, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.
 2601. The system of claim 2590, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the second conduit is further configurable to remove an oxidation product during use.
 2602. The system of claim 2590, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2603. The system of claim 2590, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2604. The system of claim 2590, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2605. The system of claim 2590, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2606. The system of claim 2590, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2607. The system of claim 2590, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2608. The system of claim 2590, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2609. The system of claim 2590, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: a heat exchanger disposed external to the formation, wherein the heat exchanger is configured to heat an oxidizing fluid during use; a conduit disposed in the opening, wherein the conduit is configured to provide the heated oxidizing fluid from the heat exchanger to at least a portion of the formation during use, wherein the system is configured to allow heat to transfer from the heated oxidizing fluid to at least the portion of the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at a reaction zone in the formation during use such that heat is generated at the reaction zone; and wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.
 2610. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises: heating the oxidizing fluid with a heat exchanger, wherein the heat exchanger is disposed external to the formation; providing the heated oxidizing fluid from the heat exchanger to the portion of the formation; and allowing heat to transfer from the heated oxidizing fluid to the portion of the formation; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.
 2611. The method of claim 2610, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.
 2612. The method of claim 2610, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.
 2613. The method of claim 2610, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.
 2614. The method of claim 2610, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.
 2615. The method of claim 2610, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.
 2616. The method of claim 2610, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.
 2617. The method of claim 2610, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.
 2618. The method of claim 2610, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2619. The method of claim 2610, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.
 2620. The method of claim 2610, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.
 2621. The method of claim 2610, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.
 2622. The method of claim 2610, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.
 2623. The method of claim 2610, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2624. The method of claim 2610, further comprising removing water from the formation prior to heating the portion.
 2625. The method of claim 2610, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.
 2626. The method of claim 2610, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2627. The method of claim 2610, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2628. The method of claim 2610, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2629. The method of claim 2610, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2630. The method of claim 2610, wherein the pyrolysis zone is substantially adjacent to the reaction zone.
 2631. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises: oxidizing a fuel gas in a heater, wherein the heater is disposed external to the formation; providing the oxidized fuel gas from the heater to the portion of the formation; and allowing heat to transfer from the oxidized fuel gas to the portion of the formation; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.
 2632. The method of claim 2631, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.
 2633. The method of claim 2631, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.
 2634. The method of claim 2631, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.
 2635. The method of claim 2631, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.
 2636. The method of claim 2631, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.
 2637. The method of claim 2631, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.
 2638. The method of claim 2631, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.
 2639. The method of claim 2631, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.
 2640. The method of claim 2631, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.
 2641. The method of claim 2631, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.
 2642. The method of claim 2631, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.
 2643. The method of claim 2631, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.
 2644. The method of claim 2631, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.
 2645. The method of claim 2631, further comprising removing water from the formation prior to heating the portion.
 2646. The method of claim 2631, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.
 2647. The method of claim 2631, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2648. The method of claim 2631, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2649. The method of claim 2631, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2650. The method of claim 2631, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2651. The method of claim 2631, wherein the pyrolysis zone is substantially adjacent to the reaction zone.
 2652. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: an insulated conductor disposed within an open wellbore in the formation, wherein the insulated conductor is configured to provide radiant heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the insulated conductor to a selected section of the formation during use.
 2653. The system of claim 2652, wherein the insulated conductor is further configured to generate heat during application of an electrical current to the insulated conductor during use.
 2654. The system of claim 2652, further comprising a support member, wherein the support member is configured to support the insulated conductor.
 2655. The system of claim 2652, further comprising a support member and a centralizer, wherein the support member is configured to support the insulated conductor, and wherein the centralizer is configured to maintain a location of the insulated conductor on the support member.
 2656. The system of claim 2652, wherein the open wellbore comprises a diameter of at least approximately 5 cm.
 2657. The system of claim 2652, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 2658. The system of claim 2652, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a rubber insulated conductor.
 2659. The system of claim 2652, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a copper wire.
 2660. The system of claim 2652, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor.
 2661. The system of claim 2652, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2662. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath.
 2663. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.
 2664. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.
 2665. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.
 2666. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.
 2667. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2668. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2669. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2670. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.
 2671. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2672. The system of claim 2652, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2673. The system of claim 2652, further comprising two additional insulated conductors, wherein the insulated conductor and the two additional insulated conductors are configured in a 3-phase Y configuration.
 2674. The system of claim 2652, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configured in a series electrical configuration.
 2675. The system of claim 2652, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configured in a parallel electrical configuration.
 2676. The system of claim 2652, wherein the insulated conductor is configured to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.
 2677. The system of claim 2652, further comprising a support member configured to support the insulated conductor, wherein the support member comprises orifices configured to provide fluid flow through the support member into the open wellbore during use.
 2678. The system of claim 2652, further comprising a support member configured to support the insulated conductor, wherein the support member comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the open wellbore during use.
 2679. The system of claim 2652, further comprising a tube coupled to the insulated conductor, wherein the tube is configured to provide a flow of fluid into the open wellbore during use.
 2680. The system of claim 2652, further comprising a tube coupled to the insulated conductor, wherein the tube comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the open wellbore during use.
 2681. The system of claim 2652, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation.
 2682. The system of claim 2652, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2683. The system of claim 2652, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2684. The system of claim 2652, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the open wellbore.
 2685. The system of claim 2652, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the open wellbore, and wherein the packing material is configured to substantially inhibit a flow of fluid between the open wellbore and the overburden casing during use.
 2686. The system of claim 2652, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the open wellbore, and wherein the packing material comprises cement.
 2687. The system of claim 2652, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configured to couple to the lead-in conductor.
 2688. The system of claim 2652, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some of the hydrocarbons in the selected section.
 2689. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: an insulated conductor configurable to be disposed within an open wellbore in the formation, wherein the insulated conductor is further configurable to provide radiant heat to at least a portion of the formation during use; and wherein the system is configurable to allow heat to transfer from the insulated conductor to a selected section of the formation during use.
 2690. The system of claim 2689, wherein the insulated conductor is further configurable to generate heat during application of an electrical current to the insulated conductor during use.
 2691. The system of claim 2689, further comprising a support member, wherein the support member is configurable to support the insulated conductor.
 2692. The system of claim 2689, further comprising a support member and a centralizer, wherein the support member is configurable to support the insulated conductor, and wherein the centralizer is configurable to maintain a location of the insulated conductor on the support member.
 2693. The system of claim 2689, wherein the open wellbore comprises a diameter of at least approximately 5 cm.
 2694. The system of claim 2689, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.
 2695. The system of claim 2689, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a rubber insulated conductor.
 2696. The system of claim 2689, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a copper wire.
 2697. The system of claim 2689, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor.
 2698. The system of claim 2689, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2699. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath.
 2700. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.
 2701. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.
 2702. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.
 2703. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.
 2704. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2705. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2706. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2707. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configurable to occupy porous spaces within the magnesium oxide.
 2708. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2709. The system of claim 2689, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2710. The system of claim 2689, further comprising two additional insulated conductors, wherein the insulated conductor and the two additional insulated conductors are configurable in a 3-phase Y configuration.
 2711. The system of claim 2689, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configurable in a series electrical configuration.
 2712. The system of claim 2689, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configurable in a parallel electrical configuration.
 2713. The system of claim 2689, wherein the insulated conductor is configurable to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.
 2714. The system of claim 2689, further comprising a support member configurable to support the insulated conductor, wherein the support member comprises orifices configurable to provide fluid flow through the support member into the open wellbore during use.
 2715. The system of claim 2689, further comprising a support member configurable to support the insulated conductor, wherein the support member comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the open wellbore during use.
 2716. The system of claim 2689, further comprising a tube coupled to the insulated conductor, wherein the tube is configurable to provide a flow of fluid into the open wellbore during use.
 2717. The system of claim 2689, further comprising a tube coupled to the first insulated conductor, wherein the tube comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the open wellbore during use.
 2718. The system of claim 2689, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation.
 2719. The system of claim 2689, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2720. The system of claim 2689, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2721. The system of claim 2689, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the open wellbore.
 2722. The system of claim 2689, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the open wellbore, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the open wellbore and the overburden casing during use.
 2723. The system of claim 2689, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the open wellbore, and wherein the packing material comprises cement.
 2724. The system of claim 2689, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configurable to couple to the lead-in conductor.
 2725. The system of claim 2689, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.
 2726. The system of claim 2689, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: an insulated conductor disposed within an open wellbore in the formation, wherein the insulated conductor is configured to provide radiant heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the insulated conductor to a selected section of the formation during use.
 2727. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to an insulated conductor to provide radiant heat to at least a portion of the formation, wherein the insulated conductor is disposed within an open wellbore in the formation; and allowing the radiant heat to transfer from the insulated conductor to a selected section of the formation.
 2728. The method of claim 2727, further comprising supporting the insulated conductor on a support member.
 2729. The method of claim 2727, further comprising supporting the insulated conductor on a support member and maintaining a location of the insulated conductor on the support member with a centralizer.
 2730. The method of claim 2727, wherein the insulated conductor is coupled to two additional insulated conductors, wherein the insulated conductor and the two insulated conductors are disposed within the open wellbore, and wherein the three insulated conductors are electrically coupled in a 3-phase Y configuration.
 2731. The method of claim 2727, wherein an additional insulated conductor is disposed within the open wellbore.
 2732. The method of claim 2727, wherein an additional insulated conductor is disposed within the open wellbore, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a series configuration.
 2733. The method of claim 2727, wherein an additional insulated conductor is disposed within the open wellbore, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a parallel configuration.
 2734. The method of claim 2727, wherein the provided heat comprises approximately 500 W/m to approximately 1150 W/m.
 2735. The method of claim 2727, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.
 2736. The method of claim 2727, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.
 2737. The method of claim 2727, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.
 2738. The method of claim 2727, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2739. The method of claim 2727, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2740. The method of claim 2727, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2741. The method of claim 2727, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.
 2742. The method of claim 2727, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2743. The method of claim 2727, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2744. The method of claim 2727, further comprising supporting the insulated conductor on a support member and flowing a fluid into the open wellbore through an orifice in the support member.
 2745. The method of claim 2727, further comprising supporting the insulated conductor on a support member and flowing a substantially constant amount of fluid into the open wellbore through critical flow orifices in the support member.
 2746. The method of claim 2727, wherein a perforated tube is disposed in the open wellbore proximate to the insulated conductor, the method further comprising flowing a fluid into the open wellbore through the perforated tube.
 2747. The method of claim 2727, wherein a tube is disposed in the open wellbore proximate to the insulated conductor, the method further comprising flowing a substantially constant amount of fluid into the open wellbore through critical flow orifices in the tube.
 2748. The method of claim 2727, further comprising supporting the insulated conductor on a support member and flowing a corrosion inhibiting fluid into the open wellbore through an orifice in the support member.
 2749. The method of claim 2727, wherein a perforated tube is disposed in the open wellbore proximate to the insulated conductor, the method further comprising flowing a corrosion inhibiting fluid into the open wellbore through the perforated tube.
 2750. The method of claim 2727, further comprising determining a temperature distribution in the insulated conductor using an electromagnetic signal provided to the insulated conductor.
 2751. The method of claim 2727, further comprising monitoring a leakage current of the insulated conductor.
 2752. The method of claim 2727, further comprising monitoring the applied electrical current.
 2753. The method of claim 2727, further comprising monitoring a voltage applied to the insulated conductor.
 2754. The method of claim 2727, further comprising monitoring a temperature in the insulated conductor with at least one thermocouple.
 2755. The method of claim 2727, further comprising electrically coupling a lead-in conductor to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 2756. The method of claim 2727, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor.
 2757. The method of claim 2727, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2758. The method of claim 2727, further comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation.
 2759. The method of claim 2727, further comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2760. The method of claim 2727, further comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2761. The method of claim 2727, further comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the open wellbore.
 2762. The method of claim 2727, further comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the open wellbore and the overburden casing with a packing material.
 2763. The method of claim 2727, further comprising heating at least the portion of the formation to pyrolyze at least some hydrocarbons within the formation.
 2764. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to an insulated conductor to provide heat to at least a portion of the formation, wherein the insulated conductor is disposed within an opening in the formation; and allowing the heat to transfer from the insulated conductor to a section of the formation.
 2765. The method of claim 2764, further comprising supporting the insulated conductor on a support member.
 2766. The method of claim 2764, further comprising supporting the insulated conductor on a support member and maintaining a location of the first insulated conductor on the support member with a centralizer.
 2767. The method of claim 2764, wherein the insulated conductor is coupled to two additional insulated conductors, wherein the insulated conductor and the two insulated conductors are disposed within the opening, and wherein the three insulated conductors are electrically coupled in a 3-phase Y configuration.
 2768. The method of claim 2764, wherein an additional insulated conductor is disposed within the opening.
 2769. The method of claim 2764, wherein an additional insulated conductor is disposed within the opening, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a series configuration.
 2770. The method of claim 2764, wherein an additional insulated conductor is disposed within the opening, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a parallel configuration.
 2771. The method of claim 2764, wherein the provided heat comprises approximately 500 W/m to approximately 1150 W/m.
 2772. The method of claim 2764, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.
 2773. The method of claim 2764, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.
 2774. The method of claim 2764, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.
 2775. The method of claim 2764, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2776. The method of claim 2764, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2777. The method of claim 2764, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2778. The method of claim 2764, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.
 2779. The method of claim 2764, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2780. The method of claim 2764, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2781. The method of claim 2764, further comprising supporting the insulated conductor on a support member and flowing a fluid into the opening through an orifice in the support member.
 2782. The method of claim 2764, further comprising supporting the insulated conductor on a support member and flowing a substantially constant amount of fluid into the opening through critical flow orifices in the support member.
 2783. The method of claim 2764, wherein a perforated tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a fluid into the opening through the perforated tube.
 2784. The method of claim 2764, wherein a tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a substantially constant amount of fluid into the opening through critical flow orifices in the tube.
 2785. The method of claim 2764, further comprising supporting the insulated conductor on a support member and flowing a corrosion inhibiting fluid into the opening through an orifice in the support member.
 2786. The method of claim 2764, wherein a perforated tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a corrosion inhibiting fluid into the opening through the perforated tube.
 2787. The method of claim 2764, further comprising determining a temperature distribution in the insulated conductor using an electromagnetic signal provided to the insulated conductor.
 2788. The method of claim 2764, further comprising monitoring a leakage current of the insulated conductor.
 2789. The method of claim 2764, further comprising monitoring the applied electrical current.
 2790. The method of claim 2764, further comprising monitoring a voltage applied to the insulated conductor.
 2791. The method of claim 2764, further comprising monitoring a temperature in the insulated conductor with at least one thermocouple.
 2792. The method of claim 2764, further comprising electrically coupling a lead-in conductor to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 2793. The method of claim 2764, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor.
 2794. The method of claim 2764, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2795. The method of claim 2764, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2796. The method of claim 2764, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2797. The method of claim 2764, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2798. The method of claim 2764, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2799. The method of claim 2764, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.
 2800. The method of claim 2764, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.
 2801. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: an insulated conductor disposed within an opening in the formation, wherein the insulated conductor is configured to provide heat to at least a portion of the formation during use, wherein the insulated conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight; and wherein the system is configured to allow heat to transfer from the insulated conductor to a selected section of the formation during use.
 2802. The system of claim 2801, wherein the insulated conductor is further configured to generate heat during application of an electrical current to the insulated conductor during use.
 2803. The system of claim 2801, further comprising a support member, wherein the support member is configured to support the insulated conductor.
 2804. The system of claim 2801, further comprising a support member and a centralizer, wherein the support member is configured to support the insulated conductor, and wherein the centralizer is configured to maintain a location of the insulated conductor on the support member.
 2805. The system of claim 2801, wherein the opening comprises a diameter of at least approximately 5 cm.
 2806. The system of claim 2801, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 2807. The system of claim 2801, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a rubber insulated conductor.
 2808. The system of claim 2801, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a copper wire.
 2809. The system of claim 2801, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor.
 2810. The system of claim 2801, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2811. The system of claim 2801, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.
 2812. The system of claim 2801, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2813. The system of claim 2801, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2814. The system of claim 2801, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2815. The system of claim 2801, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.
 2816. The system of claim 2801, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2817. The system of claim 2801, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2818. The system of claim 2801, further comprising two additional insulated conductors, wherein the insulated conductor and the two additional insulated conductors are configured in a 3-phase Y configuration.
 2819. The system of claim 2801, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configured in a series electrical configuration.
 2820. The system of claim 2801, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configured in a parallel electrical configuration.
 2821. The system of claim 2801, wherein the insulated conductor is configured to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.
 2822. The system of claim 2801, further comprising a support member configured to support the insulated conductor, wherein the support member comprises orifices configured to provide fluid flow through the support member into the opening during use.
 2823. The system of claim 2801, further comprising a support member configured to support the insulated conductor, wherein the support member comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the opening during use.
 2824. The system of claim 2801, further comprising a tube coupled to the insulated conductor, wherein the tube is configured to provide a flow of fluid into the opening during use.
 2825. The system of claim 2801, further comprising a tube coupled to the insulated conductor, wherein the tube comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the opening during use.
 2826. The system of claim 2801, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2827. The system of claim 2801, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2828. The system of claim 2801, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2829. The system of claim 2801, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2830. The system of claim 2801, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2831. The system of claim 2801, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2832. The system of claim 2801, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configured to couple to the lead-in conductor.
 2833. The system of claim 2801, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.
 2834. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: an insulated conductor configurable to be disposed within an opening in the formation, wherein the insulated conductor is further configurable to provide heat to at least a portion of the formation during use, wherein the insulated conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight; wherein the system is configurable to allow heat to transfer from the insulated conductor to a selected section of the formation during use.
 2835. The system of claim 2834, wherein the insulated conductor is further configurable to generate heat during application of an electrical current to the insulated conductor during use.
 2836. The system of claim 2834, further comprising a support member, wherein the support member is configurable to support the insulated conductor.
 2837. The system of claim 2834, further comprising a support member and a centralizer, wherein the support member is configurable to support the insulated conductor, and wherein the centralizer is configurable to maintain a location of the insulated conductor on the support member.
 2838. The system of claim 2834, wherein the opening comprises a diameter of at least approximately 5 cm.
 2839. The system of claim 2834, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.
 2840. The system of claim 2834, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a rubber insulated conductor.
 2841. The system of claim 2834, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a copper wire.
 2842. The system of claim 2834, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor.
 2843. The system of claim 2834, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2844. The system of claim 2834, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.
 2845. The system of claim 2834, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2846. The system of claim 2834, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2847. The system of claim 2834, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2848. The system of claim 2834, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configurable to occupy porous spaces within the magnesium oxide.
 2849. The system of claim 2834, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2850. The system of claim 2834, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2851. The system of claim 2834, further comprising two additional insulated conductors, wherein the insulated conductor and the two additional insulated conductors are configurable in a 3-phase Y configuration.
 2852. The system of claim 2834, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configurable in a series electrical configuration.
 2853. The system of claim 2834, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configurable in a parallel electrical configuration.
 2854. The system of claim 2834, wherein the insulated conductor is configurable to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.
 2855. The system of claim 2834, further comprising a support member configurable to support the insulated conductor, wherein the support member comprises orifices configurable to provide fluid flow through the support member into the open wellbore during use.
 2856. The system of claim 2834, further comprising a support member configurable to support the insulated conductor, wherein the support member comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the opening during use.
 2857. The system of claim 2834, further comprising a tube coupled to the insulated conductor, wherein the tube is configurable to provide a flow of fluid into the opening during use.
 2858. The system of claim 2834, further comprising a tube coupled to the insulated conductor, wherein the tube comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the opening during use.
 2859. The system of claim 2834, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2860. The system of claim 2834, further comprising an overburden casing coupled to the opening wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2861. The system of claim 2834, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2862. The system of claim 2834, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2863. The system of claim 2834, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2864. The system of claim 2834, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2865. The system of claim 2834, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configurable to couple to the lead-in conductor.
 2866. The system of claim 2834, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.
 2867. The system of claim 2834, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: an insulated conductor disposed within an opening in the formation, wherein the insulated conductor is configured to provide heat to at least a portion of the formation during use, wherein the insulated conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight; and wherein the system is configured to allow heat to transfer from the insulated conductor to a selected section of the formation during use.
 2868. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to an insulated conductor to provide heat to at least a portion of the formation, wherein the insulated conductor is disposed within an opening in the formation, and wherein the insulated conductor comprises a copper-nickel alloy of approximately 7% nickel by weight to approximately 12% nickel by weight; and allowing the heat to transfer from the insulated conductor to a selected section of the formation.
 2869. The method of claim 2868, further comprising supporting the insulated conductor on a support member.
 2870. The method of claim 2868, further comprising supporting the insulated conductor on a support member and maintaining a location of the first insulated conductor on the support member with a centralizer.
 2871. The method of claim 2868, wherein the insulated conductor is coupled to two additional insulated conductors, wherein the insulated conductor and the two insulated conductors are disposed within the opening, and wherein the three insulated conductors are electrically coupled in a 3-phase Y configuration.
 2872. The method of claim 2868, wherein an additional insulated conductor is disposed within the opening.
 2873. The method of claim 2868, wherein an additional insulated conductor is disposed within the opening, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a series configuration.
 2874. The method of claim 2868, wherein an additional insulated conductor is disposed within the opening, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a parallel configuration.
 2875. The method of claim 2868, wherein the provided heat comprises approximately 500 W/m to approximately 1150 W/m.
 2876. The method of claim 2868, wherein the copper-nickel alloy is disposed in an electrically insulating material.
 2877. The method of claim 2868, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2878. The method of claim 2868, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2879. The method of claim 2868, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2880. The method of claim 2868, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.
 2881. The method of claim 2868, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2882. The method of claim 2868, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2883. The method of claim 2868, further comprising supporting the insulated conductor on a support member and flowing a fluid into the opening through an orifice in the support member.
 2884. The method of claim 2868, further comprising supporting the insulated conductor on a support member and flowing a substantially constant amount of fluid into the opening through critical flow orifices in the support member.
 2885. The method of claim 2868, wherein a perforated tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a fluid into the opening through the perforated tube.
 2886. The method of claim 2868, wherein a tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a substantially constant amount of fluid into the opening through critical flow orifices in the tube.
 2887. The method of claim 2868, further comprising supporting the insulated conductor on a support member and flowing a corrosion inhibiting fluid into the opening through an orifice in the support member.
 2888. The method of claim 2868, wherein a perforated tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a corrosion inhibiting fluid into the opening through the perforated tube.
 2889. The method of claim 2868, further comprising determining a temperature distribution in the insulated conductor using an electromagnetic signal provided to the insulated conductor.
 2890. The method of claim 2868, further comprising monitoring a leakage current of the insulated conductor.
 2891. The method of claim 2868, further comprising monitoring the applied electrical current.
 2892. The method of claim 2868, further comprising monitoring a voltage applied to the insulated conductor.
 2893. The method of claim 2868, further comprising monitoring a temperature in the insulated conductor with at least one thermocouple.
 2894. The method of claim 2868, further comprising electrically coupling a lead-in conductor to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 2895. The method of claim 2868, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor.
 2896. The method of claim 2868, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2897. The method of claim 2868, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2898. The method of claim 2868, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2899. The method of claim 2868, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2900. The method of claim 2868, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2901. The method of claim 2868, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.
 2902. The method of claim 2868, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.
 2903. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least three insulated conductors disposed within an opening in the formation, wherein at least the three insulated conductors are electrically coupled in a 3-phase Y configuration, and wherein at least the three insulated conductors are configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from at least the three insulated conductors to a selected section of the formation during use.
 2904. The system of claim 2903, wherein at least the three insulated conductors are further configured to generate heat during application of an electrical current to at least the three insulated conductors during use.
 2905. The system of claim 2903, further comprising a support member, wherein the support member is configured to support at least the three insulated conductors.
 2906. The system of claim 2903, further comprising a support member and a centralizer, wherein the support member is configured to support at least the three insulated conductors, and wherein the centralizer is configured to maintain a location of at least the three insulated conductors on the support member.
 2907. The system of claim 2903, wherein the opening comprises a diameter of at least approximately 5 cm.
 2908. The system of claim 2903, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 2909. The system of claim 2903, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a rubber insulated conductor.
 2910. The system of claim 2903, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a copper wire.
 2911. The system of claim 2903, further comprising at least one lead-in conductor coupled to at least the three insulated conductors with a cold pin transition conductor.
 2912. The system of claim 2903, further comprising at least one lead-in conductor coupled to at least the three insulated conductors with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2913. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath.
 2914. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.
 2915. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.
 2916. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.
 2917. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.
 2918. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2919. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2920. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2921. The system of claim 2903, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.
 2922. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2923. The system of claim 2903, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2924. The system of claim 2903, wherein at least the three insulated conductors are configured to generate radiant heat of approximately 500 W/m to approximately 1150 W/m of at least the three insulated conductors during use.
 2925. The system of claim 2903, further comprising a support member configured to support at least the three insulated conductors, wherein the support member comprises orifices configured to provide fluid flow through the support member into the opening during use.
 2926. The system of claim 2903, further comprising a support member configured to support at least the three insulated conductors, wherein the support member comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the opening during use.
 2927. The system of claim 2903, further comprising a tube coupled to at least the three insulated conductors, wherein the tube is configured to provide a flow of fluid into the opening during use.
 2928. The system of claim 2903, further comprising a tube coupled to at least the three insulated conductors, wherein the tube comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the opening during use.
 2929. The system of claim 2903, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2930. The system of claim 2903, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2931. The system of claim 2903, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2932. The system of claim 2903, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2933. The system of claim 2903, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2934. The system of claim 2903, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2935. The system of claim 2903, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configured to couple to the lead-in conductor.
 2936. The system of claim 2903, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.
 2937. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least three insulated conductors configurable to be disposed within an opening in the formation, wherein at least the three insulated conductors are electrically coupled in a 3-phase Y configuration, and wherein at least the three insulated conductors are further configurable to provide heat to at least a portion of the formation during use; and wherein the system is configurable to allow heat to transfer from at least the three insulated conductors to a selected section of the formation during use.
 2938. The system of claim 2937, wherein at least the three insulated conductors are further configurable to generate heat during application of an electrical current to at least the three insulated conductors during use.
 2939. The system of claim 2937, further comprising a support member, wherein the support member is configurable to support at least the three insulated conductors.
 2940. The system of claim 2937, further comprising a support member and a centralizer, wherein the support member is configurable to support at least the three insulated conductors, and wherein the centralizer is configurable to maintain a location of at least the three insulated conductors on the support member.
 2941. The system of claim 2937, wherein the opening comprises a diameter of at least approximately 5 cm.
 2942. The system of claim 2937, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.
 2943. The system of claim 2937, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a rubber insulated conductor.
 2944. The system of claim 2937, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a copper wire.
 2945. The system of claim 2937, further comprising at least one lead-in conductor coupled to at least the three insulated conductors with a cold pin transition conductor.
 2946. The system of claim 2937, further comprising at least one lead-in conductor coupled to at least the three insulated conductors with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2947. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath.
 2948. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.
 2949. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.
 2950. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.
 2951. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.
 2952. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2953. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2954. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2955. The system of claim 2937, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configurable to occupy porous spaces within the magnesium oxide.
 2956. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2957. The system of claim 2937, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2958. The system of claim 2937, wherein at least the three insulated conductors are configurable to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.
 2959. The system of claim 2937, further comprising a support member configurable to support at least the three insulated conductors, wherein the support member comprises orifices configurable to provide fluid flow through the support member into the opening during use.
 2960. The system of claim 2937, further comprising a support member configurable to support at least the three insulated conductors, wherein the support member comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the opening during use.
 2961. The system of claim 2937, further comprising a tube coupled to at least the three insulated conductors, wherein the tube is configurable to provide a flow of fluid into the opening during use.
 2962. The system of claim 2937, further comprising a tube coupled to at least the three insulated conductors, wherein the tube comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the opening during use.
 2963. The system of claim 2937, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 2964. The system of claim 2937, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 2965. The system of claim 2937, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 2966. The system of claim 2937, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 2967. The system of claim 2937, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 2968. The system of claim 2937, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 2969. The system of claim 2937, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configurable to couple to the lead-in conductor.
 2970. The system of claim 2937, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.
 2971. The system of claim 2937, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: at least three insulated conductors disposed within an opening in the formation, wherein at least the three insulated conductors are electrically coupled in a 3-phase Y configuration, and wherein at least the three insulated conductors are configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from at least the three insulated conductors to a selected section of the formation during use.
 2972. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to at least three insulated conductors to provide heat to at least a portion of the formation, wherein at least the three insulated conductors are disposed within an opening in the formation; and allowing the heat to transfer from at least the three insulated conductors to a selected section of the formation.
 2973. The method of claim 2972, further comprising supporting at least the three insulated conductors on a support member.
 2974. The method of claim 2972, further comprising supporting at least the three insulated conductors on a support member and maintaining a location of at least the three insulated conductors on the support member with a centralizer.
 2975. The method of claim 2972, wherein the provided heat comprises approximately 500 W/m to approximately 1150 W/m.
 2976. The method of claim 2972, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.
 2977. The method of claim 2972, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.
 2978. The method of claim 2972, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.
 2979. The method of claim 2972, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.
 2980. The method of claim 2972, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.
 2981. The method of claim 2972, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.
 2982. The method of claim 2972, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.
 2983. The method of claim 2972, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.
 2984. The method of claim 2972, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.
 2985. The method of claim 2972, further comprising supporting at least the three insulated conductors on a support member and flowing a fluid into the opening through an orifice in the support member.
 2986. The method of claim 2972, further comprising supporting at least the three insulated conductors on a support member and flowing a substantially constant amount of fluid into the opening through critical flow orifices in the support member.
 2987. The method of claim 2972, wherein a perforated tube is disposed in the opening proximate to at least the three insulated conductors, the method further comprising flowing a fluid into the opening through the perforated tube.
 2988. The method of claim 2972, wherein a tube is disposed in the opening proximate to at least the three insulated conductors, the method further comprising flowing a substantially constant amount of fluid into the opening through critical flow orifices in the tube.
 2989. The method of claim 2972, further comprising supporting at least the three insulated conductors on a support member and flowing a corrosion inhibiting fluid into the opening through an orifice in the support member.
 2990. The method of claim 2972, wherein a perforated tube is disposed in the opening proximate to at least the three insulated conductors, the method further comprising flowing a corrosion inhibiting fluid into the opening through the perforated tube.
 2991. The method of claim 2972, further comprising determining a temperature distribution in at least the three insulated conductors using an electromagnetic signal provided to the insulated conductor.
 2992. The method of claim 2972, further comprising monitoring a leakage current of at least the three insulated conductors.
 2993. The method of claim 2972, further comprising monitoring the applied electrical current.
 2994. The method of claim 2972, further comprising monitoring a voltage applied to at least the three insulated conductors.
 2995. The method of claim 2972, further comprising monitoring a temperature in at least the three insulated conductors with at least one thermocouple.
 2996. The method of claim 2972, further comprising electrically coupling a lead-in conductor to at least the three insulated conductors, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 2997. The method of claim 2972, further comprising electrically coupling a lead-in conductor to at least the three insulated conductors using a cold pin transition conductor.
 2998. The method of claim 2972, further comprising electrically coupling a lead-in conductor to at least the three insulated conductors using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 2999. The method of claim 2972, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3000. The method of claim 2972, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3001. The method of claim 2972, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3002. The method of claim 2972, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3003. The method of claim 2972, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.
 3004. The method of claim 2972, further comprising heating at least the portion of the formation to substantially pyrolyze at least some of the hydrocarbons within the formation.
 3005. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a first conductor disposed in a first conduit, wherein the first conduit is disposed within an opening in the formation, and wherein the first conductor is configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the first conductor to a section of the formation during use.
 3006. The system of claim 3005, wherein the first conductor is further configured to generate heat during application of an electrical current to the first conductor.
 3007. The system of claim 3005, wherein the first conductor comprises a pipe.
 3008. The system of claim 3005, wherein the first conductor comprises stainless steel.
 3009. The system of claim 3005, wherein the first conduit comprises stainless steel.
 3010. The system of claim 3005, further comprising a centralizer configured to maintain a location of the first conductor within the first conduit.
 3011. The system of claim 3005, further comprising a centralizer configured to maintain a location of the first conductor within the first conduit, wherein the centralizer comprises ceramic material.
 3012. The system of claim 3005, further comprising a centralizer configured to maintain a location of the first conductor within the first conduit, wherein the centralizer comprises ceramic material and stainless steel.
 3013. The system of claim 3005, wherein the opening comprises a diameter of at least approximately 5 cm.
 3014. The system of claim 3005, further comprising a lead-in conductor coupled to the first conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 3015. The system of claim 3005, further comprising a lead-in conductor coupled to the first conductor, wherein the lead-in conductor comprises copper.
 3016. The system of claim 3005, further comprising a sliding electrical connector coupled to the first conductor.
 3017. The system of claim 3005, further comprising a sliding electrical connector coupled to the first conductor, wherein the sliding electrical connector is further coupled to the first conduit.
 3018. The system of claim 3005, further comprising a sliding electrical connector coupled to the first conductor, wherein the sliding electrical connector is further coupled to the first conduit, and wherein the sliding electrical connector is configured to complete an electrical circuit with the first conductor and the first conduit.
 3019. The system of claim 3005, further comprising a second conductor disposed within the first conduit and at least one sliding electrical connector coupled to the first conductor and the second conductor, wherein at least the one sliding electrical connector is configured to generate less heat than the first conductor or the second conductor during use.
 3020. The system of claim 3005, wherein the first conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.
 3021. The system of claim 3005, further comprising a fluid disposed within the first conduit, wherein the fluid is configured to maintain a pressure within the first conduit to substantially inhibit deformation of the first conduit during use.
 3022. The system of claim 3005, further comprising a thermally conductive fluid disposed within the first conduit.
 3023. The system of claim 3005, further comprising a thermally conductive fluid disposed within the first conduit, wherein the thermally conductive fluid comprises helium.
 3024. The system of claim 3005, further comprising a fluid disposed within the first conduit, wherein the fluid is configured to substantially inhibit arcing between the first conductor and the first conduit during use.
 3025. The system of claim 3005, further comprising a tube disposed within the opening external to the first conduit, wherein the tube is configured to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the first conduit and the opening to substantially inhibit deformation of the first conduit during use.
 3026. The system of claim 3005, wherein the first conductor is further configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3027. The system of claim 3005, further comprising a second conductor disposed within a second conduit and a third conductor disposed within a third conduit, wherein the first conduit, the second conduit and the third conduit are disposed in different openings of the formation, wherein the first conductor is electrically coupled to the second conductor and the third conductor, and wherein the first, second, and third conductors are configured to operate in a 3-phase Y configuration during use.
 3028. The system of claim 3005, further comprising a second conductor disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit.
 3029. The system of claim 3005, further comprising a second conductor disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit with a connector.
 3030. The system of claim 3005, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3031. The system of claim 3005, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3032. The system of claim 3005, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3033. The system of claim 3005, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3034. The system of claim 3005, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3035. The system of claim 3005, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor.
 3036. The system of claim 3005, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor, and wherein the substantially low resistance conductor comprises carbon steel.
 3037. The system of claim 3005, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing and a centralizer configured to support the substantially low resistance conductor within the overburden casing.
 3038. The system of claim 3005, wherein the heated section of the formation is substantially pyrolyzed.
 3039. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a first conductor configurable to be disposed in a first conduit, wherein the first conduit is configurable to be disposed within an opening in the formation, and wherein the first conductor is further configurable to provide heat to at least a portion of the formation during use; and wherein the system is configurable to allow heat to transfer from the first conductor to a section of the formation during use.
 3040. The system of claim 3039, wherein the first conductor is further configurable to generate heat during application of an electrical current to the first conductor.
 3041. The system of claim 3039, wherein the first conductor comprises a pipe.
 3042. The system of claim 3039, wherein the first conductor comprises stainless steel.
 3043. The system of claim 3039, wherein the first conduit comprises stainless steel.
 3044. The system of claim 3039, further comprising a centralizer configurable to maintain a location of the first conductor within the first conduit.
 3045. The system of claim 3039, further comprising a centralizer configurable to maintain a location of the first conductor within the first conduit, wherein the centralizer comprises ceramic material.
 3046. The system of claim 3039, further comprising a centralizer configurable to maintain a location of the first conductor within the first conduit, wherein the centralizer comprises ceramic material and stainless steel.
 3047. The system of claim 3039, wherein the opening comprises a diameter of at least approximately 5 cm.
 3048. The system of claim 3039, further comprising a lead-in conductor coupled to the first conductor, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.
 3049. The system of claim 3039, further comprising a lead-in conductor coupled to the first conductor, wherein the lead-in conductor comprises copper.
 3050. The system of claim 3039, further comprising a sliding electrical connector coupled to the first conductor.
 3051. The system of claim 3039, further comprising a sliding electrical connector coupled to the first conductor, wherein the sliding electrical connector is further coupled to the first conduit.
 3052. The system of claim 3039, further comprising a sliding electrical connector coupled to the first conductor, wherein the sliding electrical connector is further coupled to the first conduit, and wherein the sliding electrical connector is configurable to complete an electrical circuit with the first conductor and the first conduit.
 3053. The system of claim 3039, further comprising a second conductor disposed within the first conduit and at least one sliding electrical connector coupled to the first conductor and the second conductor, wherein at least the one sliding electrical connector is configurable to generate less heat than the first conductor or the second conductor during use.
 3054. The system of claim 3039, wherein the first conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.
 3055. The system of claim 3039, further comprising a fluid disposed within the first conduit, wherein the fluid is configurable to maintain a pressure within the first conduit to substantially inhibit deformation of the first conduit during use.
 3056. The system of claim 3039, further comprising a thermally conductive fluid disposed within the first conduit.
 3057. The system of claim 3039, further comprising a thermally conductive fluid disposed within the first conduit, wherein the thermally conductive fluid comprises helium.
 3058. The system of claim 3039, further comprising a fluid disposed within the first conduit, wherein the fluid is configurable to substantially inhibit arcing between the first conductor and the first conduit during use.
 3059. The system of claim 3039, further comprising a tube disposed within the opening external to the first conduit, wherein the tube is configurable to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the first conduit and the opening to substantially inhibit deformation of the first conduit during use.
 3060. The system of claim 3039, wherein the first conductor is further configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3061. The system of claim 3039, further comprising a second conductor disposed within a second conduit and a third conductor disposed within a third conduit, wherein the first conduit, the second conduit and the third conduit are disposed in different openings of the formation, wherein the first conductor is electrically coupled to the second conductor and the third conductor, and wherein the first, second, and third conductors are configurable to operate in a 3-phase Y configuration during use.
 3062. The system of claim 3039, further comprising a second conductor disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit.
 3063. The system of claim 3039, further comprising a second conductor disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit with a connector.
 3064. The system of claim 3039, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3065. The system of claim 3039, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3066. The system of claim 3039, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3067. The system of claim 3039, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3068. The system of claim 3039, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3069. The system of claim 3039, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor.
 3070. The system of claim 3039, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor, and wherein the substantially low resistance conductor comprises carbon steel.
 3071. The system of claim 3039, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing and a centralizer configurable to support the substantially low resistance conductor within the overburden casing.
 3072. The system of claim 3039, wherein the heated section of the formation is substantially pyrolyzed.
 3073. The system of claim 3039, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: a first conductor disposed in a first conduit, wherein the first conduit is disposed within an opening in the formation, and wherein the first conductor is configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the first conductor to a section of the formation during use.
 3074. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to a first conductor to provide heat to at least a portion of the formation, wherein the first conductor is disposed in a first conduit, and wherein the first conduit is disposed within an opening in the formation; and allowing the heat to transfer from the first conductor to a section of the formation.
 3075. The method of claim 3074, wherein the first conductor comprises a pipe.
 3076. The method of claim 3074, wherein the first conductor comprises stainless steel.
 3077. The method of claim 3074, wherein the first conduit comprises stainless steel.
 3078. The method of claim 3074, further comprising maintaining a location of the first conductor in the first conduit with a centralizer.
 3079. The method of claim 3074, further comprising maintaining a location of the first conductor in the first conduit with a centralizer, wherein the centralizer comprises ceramic material.
 3080. The method of claim 3074, further comprising maintaining a location of the first conductor in the first conduit with a centralizer, wherein the centralizer comprises ceramic material and stainless steel.
 3081. The method of claim 3074, further comprising coupling a sliding electrical connector to the first conductor.
 3082. The method of claim 3074, further comprising electrically coupling a sliding electrical connector to the first conductor and the first conduit, wherein the first conduit comprises an electrical lead configured to complete an electrical circuit with the first conductor.
 3083. The method of claim 3074, further comprising coupling a sliding electrical connector to the first conductor and the first conduit, wherein the first conduit comprises an electrical lead configured to complete an electrical circuit with the first conductor, and wherein the generated heat comprises approximately 20 percent generated by the first conduit.
 3084. The method of claim 3074, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.
 3085. The method of claim 3074, further comprising determining a temperature distribution in the first conduit using an electromagnetic signal provided to the conduit.
 3086. The method of claim 3074, further comprising monitoring the applied electrical current.
 3087. The method of claim 3074, further comprising monitoring a voltage applied to the first conductor.
 3088. The method of claim 3074, further comprising monitoring a temperature in the conduit with at least one thermocouple.
 3089. The method of claim 3074, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3090. The method of claim 3074, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3091. The method of claim 3074, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3092. The method of claim 3074, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3093. The method of claim 3074, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.
 3094. The method of claim 3074, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, and wherein the substantially low resistance conductor is electrically coupled to the first conductor.
 3095. The method of claim 3074, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor, and wherein the substantially low resistance conductor comprises carbon steel.
 3096. The method of claim 3074, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor, and wherein the method further comprises maintaining a location of the substantially low resistance conductor in the overburden casing with a centralizer support.
 3097. The method of claim 3074, further comprising electrically coupling a lead-in conductor to the first conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 3098. The method of claim 3074, further comprising electrically coupling a lead-in conductor to the first conductor, wherein the lead-in conductor comprises copper.
 3099. The method of claim 3074, further comprising maintaining a sufficient pressure between the first conduit and the formation to substantially inhibit deformation of the first conduit.
 3100. The method of claim 3074, further comprising providing a thermally conductive fluid within the first conduit.
 3101. The method of claim 3074, further comprising providing a thermally conductive fluid within the first conduit, wherein the thermally conductive fluid comprises helium.
 3102. The method of claim 3074, further comprising inhibiting arcing between the first conductor and the first conduit with a fluid disposed within the first conduit.
 3103. The method of claim 3074, further comprising removing a vapor from the opening using a perforated tube disposed proximate to the first conduit in the opening to control a pressure in the opening.
 3104. The method of claim 3074, further comprising flowing a corrosion inhibiting fluid through a perforated tube disposed proximate to the first conduit in the opening.
 3105. The method of claim 3074, wherein a second conductor is disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit.
 3106. The method of claim 3074, wherein a second conductor is disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor with a connector.
 3107. The method of claim 3074, wherein a second conductor is disposed within a second conduit and a third conductor is disposed within a third conduit, wherein the second conduit and the third conduit are disposed in different openings of the formation, wherein the first conductor is electrically coupled to the second conductor and the third conductor, and wherein the first, second, and third conductors are configured to operate in a 3-phase Y configuration.
 3108. The method of claim 3074, wherein a second conductor is disposed within the first conduit, wherein at least one sliding electrical connector is coupled to the first conductor and the second conductor, and wherein heat generated by at least the one sliding electrical connector is less than heat generated by the first conductor or the second conductor.
 3109. The method of claim 3074, wherein the first conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.
 3110. The method of claim 3074, further comprising flowing an oxidizing fluid through an orifice in the first conduit.
 3111. The method of claim 3074, further comprising disposing a perforated tube proximate to the first conduit and flowing an oxidizing fluid through the perforated tube.
 3112. The method of claim 3074, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.
 3113. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a first conductor disposed in a first conduit, wherein the first conduit is disposed within a first opening in the formation; a second conductor disposed in a second conduit, wherein the second conduit is disposed within a second opening in the formation; a third conductor disposed in a third conduit, wherein the third conduit is disposed within a third opening in the formation, wherein the first, second, and third conductors are electrically coupled in a 3-phase Y configuration, and wherein the first, second, and third conductors are configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the first, second, and third conductors to a selected section of the formation during use.
 3114. The system of claim 3113, wherein the first, second, and third conductors are further configured to generate heat during application of an electrical current to the first conductor.
 3115. The system of claim 3113, wherein the first, second, and third conductors comprise a pipe.
 3116. The system of claim 3113, wherein the first, second, and third conductors comprise stainless steel.
 3117. The system of claim 3113, wherein the first, second, and third openings comprise a diameter of at least approximately 5 cm.
 3118. The system of claim 3113, further comprising a first sliding electrical connector coupled to the first conductor and a second sliding electrical connector coupled to the second conductor and a third sliding electrical connector coupled to the third conductor.
 3119. The system of claim 3113, further comprising a first sliding electrical connector coupled to the first conductor, wherein the first sliding electrical connector is further coupled to the first conduit.
 3120. The system of claim 3113, further comprising a second sliding electrical connector coupled to the second conductor, wherein the second sliding electrical connector is further coupled to the second conduit.
 3121. The system of claim 3113, further comprising a third sliding electrical connector coupled to the third conductor, wherein the third sliding electrical connector is further coupled to the third conduit.
 3122. The system of claim 3113, wherein each of the first, second, and third conduits comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from each of the first, second, and third conductors to the section along the first section of each of the conduits is less than heat radiated from the first, second, and third conductors to the section along the second section of each of the conduits.
 3123. The system of claim 3113, further comprising a fluid disposed within the first, second, and third conduits, wherein the fluid is configured to maintain a pressure within the first conduit to substantially inhibit deformation of the first, second, and third conduits during use.
 3124. The system of claim 3113, further comprising a thermally conductive fluid disposed within the first, second, and third conduits.
 3125. The system of claim 3113, further comprising a thermally conductive fluid disposed within the first, second, and third conduits, wherein the thermally conductive fluid comprises helium.
 3126. The system of claim 3113, further comprising a fluid disposed within the first, second, and third conduits, wherein the fluid is configured to substantially inhibit arcing between the first, second, and third conductors and the first, second, and third conduits during use.
 3127. The system of claim 3113, further comprising at least one tube disposed within the first, second, and third openings external to the first, second, and third conduits, wherein at least the one tube is configured to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the first, second, and third conduits and the first, second, and third openings to substantially inhibit deformation of the first, second, and third conduits during use.
 3128. The system of claim 3113, wherein the first, second, and third conductors are further configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3129. The system of claim 3113, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation.
 3130. The system of claim 3113, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein at least the one overburden casing comprises steel.
 3131. The system of claim 3113, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein at least the one overburden casing is further disposed in cement.
 3132. The system of claim 3113, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of at least the one overburden casing and the first, second, and third openings.
 3133. The system of claim 3113, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of at least the one overburden casing and the first, second, and third openings, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the first, second, and third openings and at least the one overburden casing during use.
 3134. The system of claim 3113, wherein the heated section of the formation is substantially pyrolyzed.
 3135. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a first conductor configurable to be disposed in a first conduit, wherein the first conduit is configurable to be disposed within a first opening in the formation; a second conductor configurable to be disposed in a second conduit, wherein the second conduit is configurable to be disposed within a second opening in the formation; a third conductor configurable to be disposed in a third conduit, wherein the third conduit is configurable to be disposed within a third opening in the formation, wherein the first, second, and third conductors are further configurable to be electrically coupled in a 3-phase Y configuration, and wherein the first, second, and third conductors are further configurable to provide heat to at least a portion of the formation during use; and wherein the system is configurable to allow heat to transfer from the first, second, and third conductors to a selected section of the formation during use.
 3136. The system of claim 3135, wherein the first, second, and third conductors are further configurable to generate heat during application of an electrical current to the first conductor.
 3137. The system of claim 3135, wherein the first, second, and third conductors comprise a pipe.
 3138. The system of claim 3135, wherein the first, second, and third conductors comprise stainless steel.
 3139. The system of claim 3135, wherein each of the first, second, and third openings comprises a diameter of at least approximately 5 cm.
 3140. The system of claim 3135, further comprising a first sliding electrical connector coupled to the first conductor and a second sliding electrical connector coupled to the second conductor and a third sliding electrical connector coupled to the third conductor.
 3141. The system of claim 3135, further comprising a first sliding electrical connector coupled to the first conductor, wherein the first sliding electrical connector is further coupled to the first conduit.
 3142. The system of claim 3135, further comprising a second sliding electrical connector coupled to the second conductor, wherein the second sliding electrical connector is further coupled to the second conduit.
 3143. The system of claim 3135, further comprising a third sliding electrical connector coupled to the third conductor, wherein the third sliding electrical connector is further coupled to the third conduit.
 3144. The system of claim 3135, wherein each of the first, second, and third conduits comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from each of the first, second, and third conductors to the section along the first section of each of the conduits is less than heat radiated from the first, second, and third conductors to the section along the second section of each of the conduits.
 3145. The system of claim 3135, further comprising a fluid disposed within the first, second, and third conduits, wherein the fluid is configurable to maintain a pressure within the first conduit to substantially inhibit deformation of the first, second, and third conduits during use.
 3146. The system of claim 3135, further comprising a thermally conductive fluid disposed within the first, second, and third conduits.
 3147. The system of claim 3135, further comprising a thermally conductive fluid disposed within the first, second, and third conduits, wherein the thermally conductive fluid comprises helium.
 3148. The system of claim 33135, further comprising a fluid disposed within the first, second, and third conduits, wherein the fluid is configurable to substantially inhibit arcing between the first, second, and third conductors and the first, second, and third conduits during use.
 3149. The system of claim 3135, further comprising at least one tube disposed within the first, second, and third openings external to the first, second, and third conduits, wherein at least the one tube is configurable to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the first, second, and third conduits and the first, second, and third openings to substantially inhibit deformation of the first, second, and third conduits during use.
 3150. The system of claim 3135, wherein the first, second, and third conductors are further configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3151. The system of claim 3135, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation.
 3152. The system of claim 3135, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein at least the one overburden casing comprises steel.
 3153. The system of claim 3135, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein at least the one overburden casing is further disposed in cement.
 3154. The system of claim 3135, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of at least the one overburden casing and the first, second, and third openings.
 3155. The system of claim 3135, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of at least the one overburden casing and the first, second, and third openings, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the first, second, and third openings and at least the one overburden casing during use.
 3156. The system of claim 3135, wherein the heated section of the formation is substantially pyrolyzed.
 3157. The system of claim 3135, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: a first conductor disposed in a first conduit, wherein the first conduit is disposed within a first opening in the formation; a second conductor disposed in a second conduit, wherein the second conduit is disposed within a second opening in the formation; a third conductor disposed in a third conduit, wherein the third conduit is disposed within a third opening in the formation, wherein the first, second, and third conductors are electrically coupled in a 3-phase Y configuration, and wherein the first, second, and third conductors are configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the first, second, and third conductors to a selected section of the formation during use.
 3158. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to a first conductor to provide heat to at least a portion of the formation, wherein the first conductor is disposed in a first conduit, and wherein the first conduit is disposed within a first opening in the formation; applying an electrical current to a second conductor to provide heat to at least a portion of the formation, wherein the second conductor is disposed in a second conduit, and wherein the second conduit is disposed within a second opening in the formation; applying an electrical current to a third conductor to provide heat to at least a portion of the formation, wherein the third conductor is disposed in a third conduit, and wherein the third conduit is disposed within a third opening in the formation; and allowing the heat to transfer from the first, second, and third conductors to a selected section of the formation.
 3159. The method of claim 3158, wherein the first, second, and third conductors comprise a pipe.
 3160. The method of claim 3158, wherein the first, second, and third conductors comprise stainless steel.
 3161. The method of claim 3158, wherein the first, second, and third conduits comprise stainless steel.
 3162. The method of claim 3158, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.
 3163. The method of claim 3158, further comprising determining a temperature distribution in the first, second, and third conduits using an electromagnetic signal provided to the first, second, and third conduits.
 3164. The method of claim 3158, further comprising monitoring the applied electrical current.
 3165. The method of claim 3158, further comprising monitoring a voltage applied to the first, second, and third conductors.
 3166. The method of claim 3158, further comprising monitoring a temperature in the first, second, and third conduits with at least one thermocouple.
 3167. The method of claim 3158, further comprising maintaining a sufficient pressure between the first, second, and third conduits and the first, second, and third openings to substantially inhibit deformation of the first, second, and third conduits.
 3168. The method of claim 3158, further comprising providing a thermally conductive fluid within the first, second, and third conduits.
 3169. The method of claim 3158, further comprising providing a thermally conductive fluid within the first, second, and third conduits, wherein the thermally conductive fluid comprises helium.
 3170. The method of claim 3158, further comprising inhibiting arcing between the first, second, and third conductors and the first, second, and third conduits with a fluid disposed within the first, second, and third conduits.
 3171. The method of claim 3158, further comprising removing a vapor from the first, second, and third openings using at least one perforated tube disposed proximate to the first, second, and third conduits in the first, second, and third openings to control a pressure in the first, second, and third openings.
 3172. The method of claim 3158, wherein the first, second, and third conduits comprise a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first, second, and third conductors to the section along the first section of the first, second, and third conduits is less than heat radiated from the first, second, and third conductors to the section along the second section of the first, second, and third conduits.
 3173. The method of claim 3158, further comprising flowing an oxidizing fluid through an orifice in the first, second, and third conduits.
 3174. The method of claim 3158, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.
 3175. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a first conductor disposed in a conduit, wherein the conduit is disposed within an opening in the formation; and a second conductor disposed in the conduit, wherein the second conductor is electrically coupled to the first conductor with a connector, and wherein the first and second conductors are configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the first and second conductors to a selected section of the formation during use.
 3176. The system of claim 3175, wherein the first conductor is further configured to generate heat during application of an electrical current to the first conductor.
 3177. The system of claim 3175, wherein the first and second conductors comprise a pipe.
 3178. The system of claim 3175, wherein the first and second conductors comprise stainless steel.
 3179. The system of claim 3175, wherein the conduit comprises stainless steel.
 3180. The system of claim 3175, further comprising a centralizer configured to maintain a location of the first and second conductors within the conduit.
 3181. The system of claim 3175, further comprising a centralizer configured to maintain a location of the first and second conductors within the conduit, wherein the centralizer comprises ceramic material.
 3182. The system of claim 3175, further comprising a centralizer configured to maintain a location of the first and second conductors within the conduit, wherein the centralizer comprises ceramic material and stainless steel.
 3183. The system of claim 3175, wherein the opening comprises a diameter of at least approximately 5 cm.
 3184. The system of claim 3175, further comprising a lead-in conductor coupled to the first and second conductors, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 3185. The system of claim 3175, further comprising a lead-in conductor coupled to the first and second conductors, wherein the lead-in conductor comprises copper.
 3186. The system of claim 3175, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.
 3187. The system of claim 3175, further comprising a fluid disposed within the conduit, wherein the fluid is configured to maintain a pressure within the conduit to substantially inhibit deformation of the conduit during use.
 3188. The system of claim 3175, further comprising a thermally conductive fluid disposed within the conduit.
 3189. The system of claim 3175, further comprising a thermally conductive fluid disposed within the conduit, wherein the thermally conductive fluid comprises helium.
 3190. The system of claim 3175, further comprising a fluid disposed within the conduit, wherein the fluid is configured to substantially inhibit arcing between the first and second conductors and the conduit during use.
 3191. The system of claim 3175, further comprising a tube disposed within the opening external to the conduit, wherein the tube is configured to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the conduit and the opening to substantially inhibit deformation of the conduit during use.
 3192. The system of claim 3175, wherein the first and second conductors are further configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3193. The system of claim 3175, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3194. The system of claim 3175, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3195. The system of claim 3175, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3196. The system of claim 3175, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3197. The system of claim 3175, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3198. The system of claim 3175, wherein the heated section of the formation is substantially pyrolyzed.
 3199. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: a first conductor configurable to be disposed in a conduit, wherein the conduit is configurable to be disposed within an opening in the formation; and a second conductor configurable to be disposed in the conduit, wherein the second conductor is configurable to be electrically coupled to the first conductor with a connector, and wherein the first and second conductors are further configurable to provide heat to at least a portion of the formation during use; and wherein the system is configurable to allow heat to transfer from the first and second conductors to a selected section of the formation during use.
 3200. The system of claim 3199, wherein the first conductor is further configurable to generate heat during application of an electrical current to the first conductor.
 3201. The system of claim 3199, wherein the first and second conductors comprise a pipe.
 3202. The system of claim 3199, wherein the first and second conductors comprise stainless steel.
 3203. The system of claim 3199, wherein the conduit comprises stainless steel.
 3204. The system of claim 3199, further comprising a centralizer configurable to maintain a location of the first and second conductors within the conduit.
 3205. The system of claim 3199, further comprising a centralizer configurable to maintain a location of the first and second conductors within the conduit, wherein the centralizer comprises ceramic material.
 3206. The system of claim 3199, further comprising a centralizer configurable to maintain a location of the first and second conductors within the conduit, wherein the centralizer comprises ceramic material and stainless steel.
 3207. The system of claim 3199, wherein the opening comprises a diameter of at least approximately 5 cm.
 3208. The system of claim 3199, further comprising a lead-in conductor coupled to the first and second conductors, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.
 3209. The system of claim 3199, further comprising a lead-in conductor coupled to the first and second conductors, wherein the lead-in conductor comprises copper.
 3210. The system of claim 3199, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.
 3211. The system of claim 3199, further comprising a fluid disposed within the conduit, wherein the fluid is configurable to maintain a pressure within the conduit to substantially inhibit deformation of the conduit during use.
 3212. The system of claim 3199, further comprising a thermally conductive fluid disposed within the conduit.
 3213. The system of claim 3199, further comprising a thermally conductive fluid disposed within the conduit, wherein the thermally conductive fluid comprises helium.
 3214. The system of claim 3199, further comprising a fluid disposed within the conduit, wherein the fluid is configurable to substantially inhibit arcing between the first and second conductors and the conduit during use.
 3215. The system of claim 3199, further comprising a tube disposed within the opening external to the conduit, wherein the tube is configurable to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the conduit and the opening to substantially inhibit deformation of the conduit during use.
 3216. The system of claim 3199, wherein the first and second conductors are further configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3217. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3218. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3219. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3220. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3221. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3222. The system of claim 3199, wherein the heated section of the formation is substantially pyrolyzed.
 3223. The system of claim 3199, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: a first conductor disposed in a conduit, wherein the conduit is disposed within an opening in the formation; a second conductor disposed in the conduit, wherein the second conductor is electrically coupled to the first conductor with a connector, and wherein the first and second conductors are configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the first and second conductors to a selected section of the formation during use.
 3224. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to at least two conductors to provide heat to at least a portion of the formation, wherein at least the two conductors are disposed within a conduit, wherein the conduit is disposed within an opening in the formation, and wherein at least the two conductors are electrically coupled with a connector; and allowing heat to transfer from at least the two conductors to a selected section of the formation.
 3225. The method of claim 3224, wherein at least the two conductors comprise a pipe.
 3226. The method of claim 3224, wherein at least the two conductors comprise stainless steel.
 3227. The method of claim 3224, wherein the conduit comprises stainless steel.
 3228. The method of claim 3224, further comprising maintaining a location of at least the two conductors in the conduit with a centralizer.
 3229. The method of claim 3224, further comprising maintaining a location of at least the two conductors in the conduit with a centralizer, wherein the centralizer comprises ceramic material.
 3230. The method of claim 3224, further comprising maintaining a location of at least the two conductors in the conduit with a centralizer, wherein the centralizer comprises ceramic material and stainless steel.
 3231. The method of claim 3224, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.
 3232. The method of claim 3224, further comprising determining a temperature distribution in the conduit using an electromagnetic signal provided to the conduit.
 3233. The method of claim 3224, further comprising monitoring the applied electrical current.
 3234. The method of claim 3224, further comprising monitoring a voltage applied to at least the two conductors.
 3235. The method of claim 3224, further comprising monitoring a temperature in the conduit with at least one thermocouple.
 3236. The method of claim 3224, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3237. The method of claim 3224, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3238. The method of claim 3224, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3239. The method of claim 3224, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3240. The method of claim 3224, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.
 3241. The method of claim 3224, further comprising maintaining a sufficient pressure between the conduit and the formation to substantially inhibit deformation of the conduit.
 3242. The method of claim 3224, further comprising providing a thermally conductive fluid within the conduit.
 3243. The method of claim 3224, further comprising providing a thermally conductive fluid within the conduit, wherein the thermally conductive fluid comprises helium.
 3244. The method of claim 3224, further comprising inhibiting arcing between at least the two conductors and the conduit with a fluid disposed within the conduit.
 3245. The method of claim 3224, further comprising removing a vapor from the opening using a perforated tube disposed proximate to the conduit in the opening to control a pressure in the opening.
 3246. The method of claim 3224, further comprising flowing a corrosion inhibiting fluid through a perforated tube disposed proximate to the conduit in the opening.
 3247. The method of claim 3224, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.
 3248. The method of claim 3224, further comprising flowing an oxidizing fluid through an orifice in the conduit.
 3249. The method of claim 3224, further comprising disposing a perforated tube proximate to the conduit and flowing an oxidizing fluid through the perforated tube.
 3250. The method of claim 3224, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.
 3251. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least one conductor disposed in a conduit, wherein the conduit is disposed within an opening in the formation, and wherein at least the one conductor is configured to provide heat to at least a first portion of the formation during use; at least one sliding connector, wherein at least the one sliding connector is coupled to at least the one conductor, wherein at least the one sliding connector is configured to provide heat during use, and wherein heat provided by at least the one sliding connector is substantially less than the heat provided by at least the one conductor during use; and wherein the system is configured to allow heat to transfer from at least the one conductor to a section of the formation during use.
 3252. The system of claim 3251, wherein at least the one conductor is further configured to generate heat during application of an electrical current to at least the one conductor.
 3253. The system of claim 3251, wherein at least the one conductor comprises a pipe.
 3254. The system of claim 3251, wherein at least the one conductor comprises stainless steel.
 3255. The system of claim 3251, wherein the conduit comprises stainless steel.
 3256. The system of claim 3251, further comprising a centralizer configured to maintain a location of at least the one conductor within the conduit.
 3257. The system of claim 3251, further comprising a centralizer configured to maintain a location of at least the one conductor within the conduit, wherein the centralizer comprises ceramic material.
 3258. The system of claim 3251, further comprising a centralizer configured to maintain a location of at least the one conductor within the conduit, wherein the centralizer comprises ceramic material and stainless steel.
 3259. The system of claim 3251, wherein the opening comprises a diameter of at least approximately 5 cm.
 3260. The system of claim 3251, further comprising a lead-in conductor coupled to at least the one conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 3261. The system of claim 3251, further comprising a lead-in conductor coupled to at least the one conductor, wherein the lead-in conductor comprises copper.
 3262. The system of claim 3251, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.
 3263. The system of claim 3251, further comprising a fluid disposed within the conduit, wherein the fluid is configured to maintain a pressure within the conduit to substantially inhibit deformation of the conduit during use.
 3264. The system of claim 3251, further comprising a thermally conductive fluid disposed within the conduit.
 3265. The system of claim 3251, further comprising a thermally conductive fluid disposed within the conduit, wherein the thermally conductive fluid comprises helium.
 3266. The system of claim 3251, further comprising a fluid disposed within the conduit, wherein the fluid is configured to substantially inhibit arcing between at least the one conductor and the conduit during use.
 3267. The system of claim 3251, further comprising a tube disposed within the opening external to the conduit, wherein the tube is configured to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the conduit and the opening to substantially inhibit deformation of the conduit during use.
 3268. The system of claim 3251, wherein at least the one conductor is further configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3269. The system of claim 3251, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3270. The system of claim 3251, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3271. The system of claim 3251, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3272. The system of claim 3251, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3273. The system of claim 3251, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3274. The system of claim 3251, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor.
 3275. The system of claim 3251, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor, and wherein the substantially low resistance conductor comprises carbon steel.
 3276. The system of claim 3251, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing and a centralizer configured to support the substantially low resistance conductor within the overburden casing.
 3277. The system of claim 3251, wherein the heated section of the formation is substantially pyrolyzed.
 3278. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least one conductor configurable to be disposed in a conduit, wherein the conduit is configurable to be disposed within an opening in the formation, and wherein at least the one conductor is further configurable to provide heat to at least a first portion of the formation during use; at least one sliding connector, wherein at least the one sliding connector is configurable to be coupled to at least the one conductor, wherein at least the one sliding connector is further configurable to provide heat during use, and wherein heat provided by at least the one sliding connector is substantially less than the heat provided by at least the one conductor during use; and wherein the system is configurable to allow heat to transfer from at least the one conductor to a section of the formation during use.
 3279. The system of claim 3278, wherein at least the one conductor is further configurable to generate heat during application of an electrical current to at least the one conductor.
 3280. The system of claim 3278, wherein at least the one conductor comprises a pipe.
 3281. The system of claim 3278, wherein at least the one conductor comprises stainless steel.
 3282. The system of claim 3278, wherein the conduit comprises stainless steel.
 3283. The system of claim 3278, further comprising a centralizer configurable to maintain a location of at least the one conductor within the conduit.
 3284. The system of claim 3278, further comprising a centralizer configurable to maintain a location of at least the one conductor within the conduit, wherein the centralizer comprises ceramic material.
 3285. The system of claim 3278, further comprising a centralizer configurable to maintain a location of at least the one conductor within the conduit, wherein the centralizer comprises ceramic material and stainless steel.
 3286. The system of claim 3278, wherein the opening comprises a diameter of at least approximately 5 cm.
 3287. The system of claim 3278, further comprising a lead-in conductor coupled to at least the one conductor, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.
 3288. The system of claim 3278, further comprising a lead-in conductor coupled to at least the one conductor, wherein the lead-in conductor comprises copper.
 3289. The system of claim 3278, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.
 3290. The system of claim 3278, further comprising a fluid disposed within the conduit, wherein the fluid is configurable to maintain a pressure within the conduit to substantially inhibit deformation of the conduit during use.
 3291. The system of claim 3278, further comprising a thermally conductive fluid disposed within the conduit.
 3292. The system of claim 3278, further comprising a thermally conductive fluid disposed within the conduit, wherein the thermally conductive fluid comprises helium.
 3293. The system of claim 3278, further comprising a fluid disposed within the conduit, wherein the fluid is configurable to substantially inhibit arcing between at least the one conductor and the conduit during use.
 3294. The system of claim 3278, further comprising a tube disposed within the opening external to the conduit, wherein the tube is configurable to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the conduit and the opening to substantially inhibit deformation of the conduit during use.
 3295. The system of claim 3278, wherein at least the one conductor is further configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3296. The system of claim 3278, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3297. The system of claim 3278, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3298. The system of claim 3278, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3299. The system of claim 3278, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3300. The system of claim 3278, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3301. The system of claim 3278, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor.
 3302. The system of claim 3278, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor, and wherein the substantially low resistance conductor comprises carbon steel.
 3303. The system of claim 3278, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing and a centralizer configurable to support the substantially low resistance conductor within the overburden casing.
 3304. The system of claim 3278, wherein the heated section of the formation is substantially pyrolyzed.
 3305. The system of claim 3278, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: at least one conductor disposed in a conduit, wherein the conduit is disposed within an opening in the formation, and wherein at least the one conductor is configured to provide heat to at least a first portion of the formation during use; at least one sliding connector, wherein at least the one sliding connector is coupled to at least the one conductor, wherein at least the one sliding connector is configured to provide heat during use, and wherein heat provided by at least the one sliding connector is substantially less than the heat provided by at least the one conductor during use; and wherein the system is configured to allow heat to transfer from at least the one conductor to a section of the formation during use.
 3306. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to at least one conductor and at least one sliding connector to provide heat to at least a portion of the formation, wherein at least the one conductor and at least the one sliding connector are disposed within a conduit, and wherein heat provided by at least the one conductor is substantially greater than heat provided by at least the one sliding connector; and allowing the heat to transfer from at least the one conductor and at least the one sliding connector to a section of the formation.
 3307. The method of claim 3306, wherein at least the one conductor comprises a pipe.
 3308. The method of claim 3306, wherein at least the one conductor comprises stainless steel.
 3309. The method of claim 3306, wherein the conduit comprises stainless steel.
 3310. The method of claim 3306, further comprising maintaining a location of at least the one conductor in the conduit with a centralizer.
 3311. The method of claim 3306, further comprising maintaining a location of at least the one conductor in the conduit with a centralizer, wherein the centralizer comprises ceramic material.
 3312. The method of claim 3306, further comprising maintaining a location of at least the one conductor in the conduit with a centralizer, wherein the centralizer comprises ceramic material and stainless steel.
 3313. The method of claim 3306, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.
 3314. The method of claim 3306, further comprising determining a temperature distribution in the conduit using an electromagnetic signal provided to the conduit.
 3315. The method of claim 3306, further comprising monitoring the applied electrical current.
 3316. The method of claim 3306, further comprising monitoring a voltage applied to at least the one conductor.
 3317. The method of claim 3306, further comprising monitoring a temperature in the conduit with at least one thermocouple.
 3318. The method of claim 3306, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3319. The method of claim 3306, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3320. The method of claim 3306, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3321. The method of claim 3306, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3322. The method of claim 3306, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.
 3323. The method of claim 3306, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, and wherein the substantially low resistance conductor is electrically coupled to at least the one conductor.
 3324. The method of claim 3306, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor, and wherein the substantially low resistance conductor comprises carbon steel.
 3325. The method of claim 3306, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor, and wherein the method further comprises maintaining a location of the substantially low resistance conductor in the overburden casing with a centralizer support.
 3326. The method of claim 3306, further comprising electrically coupling a lead-in conductor to at least the one conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 3327. The method of claim 3306, further comprising electrically coupling a lead-in conductor to at least the one conductor, wherein the lead-in conductor comprises copper.
 3328. The method of claim 3306, further comprising maintaining a sufficient pressure between the conduit and the formation to substantially inhibit deformation of the conduit.
 3329. The method of claim 3306, further comprising providing a thermally conductive fluid within the conduit.
 3330. The method of claim 3306, further comprising providing a thermally conductive fluid within the conduit, wherein the thermally conductive fluid comprises helium.
 3331. The method of claim 3306, further comprising inhibiting arcing between the conductor and the conduit with a fluid disposed within the conduit.
 3332. The method of claim 3306, further comprising removing a vapor from the opening using a perforated tube disposed proximate to the conduit in the opening to control a pressure in the opening.
 3333. The method of claim 3306, further comprising flowing a corrosion inhibiting fluid through a perforated tube disposed proximate to the conduit in the opening.
 3334. The method of claim 3306, further comprising flowing an oxidizing fluid through an orifice in the conduit.
 3335. The method of claim 3306, further comprising disposing a perforated tube proximate to the conduit and flowing an oxidizing fluid through the perforated tube.
 3336. The method of claim 3306, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.
 3337. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least one elongated member disposed within an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from at least the one elongated member to a section of the formation during use.
 3338. The system of claim 3337, wherein at least the one elongated member comprises stainless steel.
 3339. The system of claim 3337, wherein at least the one elongated member is further configured to generate heat during application of an electrical current to at least the one elongated member.
 3340. The system of claim 3337, further comprising a support member coupled to at least the one elongated member, wherein the support member is configured to support at least the one elongated member.
 3341. The system of claim 3337, further comprising a support member coupled to at least the one elongated member, wherein the support member is configured to support at least the one elongated member, and wherein the support member comprises openings.
 3342. The system of claim 3337, further comprising a support member coupled to at least the one elongated member, wherein the support member is configured to support at least the one elongated member, wherein the support member comprises openings, wherein the openings are configured to flow a fluid along a length of at least the one elongated member during use, and wherein the fluid is configured to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use.
 3343. The system of claim 3337, further comprising a tube disposed in the opening, wherein the tube comprises openings, wherein the openings are configured to flow a fluid along a length of at least the one elongated member during use, and wherein the fluid is configured to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use.
 3344. The system of claim 3337, further comprising a centralizer coupled to at least the one elongated member, wherein the centralizer is configured to electrically isolate at least the one elongated member.
 3345. The system of claim 3337, further comprising a centralizer coupled to at least the one elongated member and a support member coupled to at least the one elongated member, wherein the centralizer is configured to maintain a location of at least the one elongated member on the support member.
 3346. The system of claim 3337, wherein the opening comprises a diameter of at least approximately 5 cm.
 3347. The system of claim 3337, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 3348. The system of claim 3337, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a rubber insulated conductor.
 3349. The system of claim 3337, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises copper wire.
 3350. The system of claim 3337, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor.
 3351. The system of claim 3337, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 3352. The system of claim 3337, wherein at least the one elongated member is arranged in a series electrical configuration.
 3353. The system of claim 3337, wherein at least the one elongated member is arranged in a parallel electrical configuration.
 3354. The system of claim 3337, wherein at least the one elongated member is configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3355. The system of claim 3337, further comprising a perforated tube disposed in the opening external to at least the one elongated member, wherein the perforated tube is configured to remove vapor from the opening to control a pressure in the opening during use.
 3356. The system of claim 3337, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3357. The system of claim 3337, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3358. The system of claim 3337, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3359. The system of claim 3337, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3360. The system of claim 3337, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 3361. The system of claim 3337, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3362. The system of claim 3337, wherein the heated section of the formation is substantially pyrolyzed.
 3363. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least one elongated member configurable to be disposed within an opening in the formation, wherein at least the one elongated member is further configurable to provide heat to at least a portion of the formation during use; and wherein the system is configurable to allow heat to transfer from at least the one elongated member to a section of the formation during use.
 3364. The system of claim 3363, wherein at least the one elongated member comprises stainless steel.
 3365. The system of claim 3363, wherein at least the one elongated member is further configurable to generate heat during application of an electrical current to at least the one elongated member.
 3366. The system of claim 3363, further comprising a support member coupled to at least the one elongated member, wherein the support member is configurable to support at least the one elongated member.
 3367. The system of claim 3363, further comprising a support member coupled to at least the one elongated member, wherein the support member is configurable to support at least the one elongated member, and wherein the support member comprises openings.
 3368. The system of claim 3363, further comprising a support member coupled to at least the one elongated member, wherein the support member is configurable to support at least the one elongated member, wherein the support member comprises openings, wherein the openings are configurable to flow a fluid along a length of at least the one elongated member during use, and wherein the fluid is configurable to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use.
 3369. The system of claim 3363, further comprising a tube disposed in the opening, wherein the tube comprises openings, wherein the openings are configurable to flow a fluid along a length of at least the one elongated member during use, and wherein the fluid is configurable to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use.
 3370. The system of claim 3363, further comprising a centralizer coupled to at least the one elongated member, wherein the centralizer is configurable to electrically isolate at least the one elongated member.
 3371. The system of claim 3363, further comprising a centralizer coupled to at least the one elongated member and a support member coupled to at least the one elongated member, wherein the centralizer is configurable to maintain a location of at least the one elongated member on the support member.
 3372. The system of claim 3363, wherein the opening comprises a diameter of at least approximately 5 cm.
 3373. The system of claim 3363, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.
 3374. The system of claim 3363, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a rubber insulated conductor.
 3375. The system of claim 3363, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises copper wire.
 3376. The system of claim 3363, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor.
 3377. The system of claim 3363, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 3378. The system of claim 3363, wherein at least the one elongated member is arranged in a series electrical configuration.
 3379. The system of claim 3363, wherein at least the one elongated member is arranged in a parallel electrical configuration.
 3380. The system of claim 3363, wherein at least the one elongated member is configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3381. The system of claim 3363, further comprising a perforated tube disposed in the opening external to at least the one elongated member, wherein the perforated tube is configurable to remove vapor from the opening to control a pressure in the opening during use.
 3382. The system of claim 3363, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3383. The system of claim 3363, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3384. The system of claim 3363, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3385. The system of claim 3363, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3386. The system of claim 3363, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 3387. The system of claim 3363, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3388. The system of claim 3363, wherein the heated section of the formation is substantially pyrolyzed.
 3389. The system of claim 3363, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: at least one elongated member disposed within an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from at least the one elongated member to a section of the formation during use.
 3390. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to at least one elongated member to provide heat to at least a portion of the formation, wherein at least the one elongated member is disposed within an opening of the formation; and allowing heat to transfer from at least the one elongated member to a section of the formation.
 3391. The method of claim 3390, wherein at least the one elongated member comprises a metal strip.
 3392. The method of claim 3390, wherein at least the one elongated member comprises a metal rod.
 3393. The method of claim 3390, wherein at least the one elongated member comprises stainless steel.
 3394. The method of claim 3390, further comprising supporting at least the one elongated member on a center support member.
 3395. The method of claim 3390, further comprising supporting at least the one elongated member on a center support member, wherein the center support member comprises a tube.
 3396. The method of claim 3390, further comprising electrically isolating at least the one elongated member with a centralizer.
 3397. The method of claim 3390, further comprising laterally spacing at least the one elongated member with a centralizer.
 3398. The method of claim 3390, further comprising electrically coupling at least the one elongated member in a series configuration.
 3399. The method of claim 3390, further comprising electrically coupling at least the one elongated member in a parallel configuration.
 3400. The method of claim 3390, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.
 3401. The method of claim 3390, further comprising determining a temperature distribution in at least the one elongated member using an electromagnetic signal provided to at least the one elongated member.
 3402. The method of claim 3390, further comprising monitoring the applied electrical current.
 3403. The method of claim 3390, further comprising monitoring a voltage applied to at least the one elongated member.
 3404. The method of claim 3390, further comprising monitoring a temperature in at least the one elongated member with at least one thermocouple.
 3405. The method of claim 3390, further comprising supporting at least the one elongated member on a center support member, wherein the center support member comprises openings, the method further comprising flowing an oxidizing fluid through the openings to substantially inhibit carbon deposition proximate to or on at least the one elongated member.
 3406. The method of claim 3390, further comprising flowing an oxidizing fluid through a tube disposed proximate to at least the one elongated member to substantially inhibit carbon deposition proximate to or on at least the one elongated member.
 3407. The method of claim 3390, further comprising flowing an oxidizing fluid through an opening in at least the one elongated member to substantially inhibit carbon deposition proximate to or on at least the one elongated member.
 3408. The method of claim 3390, further comprising electrically coupling a lead-in conductor to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 3409. The method of claim 3390, further comprising electrically coupling a lead-in conductor to at least the one elongated member using a cold pin transition conductor.
 3410. The method of claim 3390, further comprising electrically coupling a lead-in conductor to at least the one elongated member using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 3411. The method of claim 3390, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3412. The method of claim 3390, further comprising casing coupling overburden casing to the opening, wherein the overburden casing comprises steel.
 3413. The method of claim 3390, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in cement.
 3414. The method of claim 3390, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3415. The method of claim 3390, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with the packing material.
 3416. The method of claim 3390, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.
 3417. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least one elongated member disposed within an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed within the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to the opening during use, and wherein the oxidizing fluid is selected to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use; and wherein the system is configured to allow heat to transfer from at least the one elongated member to a section of the formation during use.
 3418. The system of claim 3417, wherein at least the one elongated member comprises stainless steel.
 3419. The system of claim 3417, wherein at least the one elongated member is further configured to generate heat during application of an electrical current to at least the one elongated member.
 3420. The system of claim 3417, wherein at least the one elongated member is coupled to the conduit, wherein the conduit is further configured to support at least the one elongated member.
 3421. The system of claim 3417, wherein at least the one elongated member is coupled to the conduit, wherein the conduit is further configured to support at least the one elongated member, and wherein the conduit comprises openings.
 3422. The system of claim 3417, further comprising a centralizer coupled to at least the one elongated member and the conduit, wherein the centralizer is configured to electrically isolate at least the one elongated member from the conduit.
 3423. The system of claim 3417, further comprising a centralizer coupled to at least the one elongated member and the conduit, wherein the centralizer is configured to maintain a location of at least the one elongated member on the conduit.
 3424. The system of claim 3417, wherein the opening comprises a diameter of at least approximately 5 cm.
 3425. The system of claim 3417, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 3426. The system of claim 3417, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a rubber insulated conductor.
 3427. The system of claim 3417, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises copper wire.
 3428. The system of claim 3417, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor.
 3429. The system of claim 3417, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 3430. The system of claim 3417, wherein at least the one elongated member is arranged in a series electrical configuration.
 3431. The system of claim 3417, wherein at least the one elongated member is arranged in a parallel electrical configuration.
 3432. The system of claim 3417, wherein at least the one elongated member is configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3433. The system of claim 3417, further comprising a perforated tube disposed in the opening external to at least the one elongated member, wherein the perforated tube is configured to remove vapor from the opening to control a pressure in the opening during use.
 3434. The system of claim 3417, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3435. The system of claim 3417, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3436. The system of claim 3417, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3437. The system of claim 3417, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3438. The system of claim 3417, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 3439. The system of claim 3417, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3440. The system of claim 3417, wherein the heated section of the formation is substantially pyrolyzed.
 3441. A system configurable to heat a relatively permeable formation containing heavy hydrocarbons, comprising: at least one elongated member configurable to be disposed within an opening in the formation, wherein at least the one elongated member is further configurable to provide heat to at least a portion of the formation during use; a conduit configurable to be disposed within the opening, wherein the conduit is further configurable to provide an oxidizing fluid from the oxidizing fluid source to the opening during use, and wherein the system is configurable to allow the oxidizing fluid to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use; and wherein the system is further configurable to allow heat to transfer from at least the one elongated member to a section of the formation during use.
 3442. The system of claim 3441, wherein at least the one elongated member comprises stainless steel.
 3443. The system of claim 3441, wherein at least the one elongated member is further configurable to generate heat during application of an electrical current to at least the one elongated member.
 3444. The system of claim 3441, wherein at least the one elongated member is coupled to the conduit, wherein the conduit is further configurable to support at least the one elongated member.
 3445. The system of claim 3441, wherein at least the one elongated member is coupled to the conduit, wherein the conduit is further configurable to support at least the one elongated member, and wherein the conduit comprises openings.
 3446. The system of claim 3441, further comprising a centralizer coupled to at least the one elongated member and the conduit, wherein the centralizer is configurable to electrically isolate at least the one elongated member from the conduit.
 3447. The system of claim 3441, further comprising a centralizer coupled to at least the one elongated member and the conduit, wherein the centralizer is configurable to maintain a location of at least the one elongated member on the conduit.
 3448. The system of claim 3441, wherein the opening comprises a diameter of at least approximately 5 cm.
 3449. The system of claim 3441, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.
 3450. The system of claim 3441, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a rubber insulated conductor.
 3451. The system of claim 3441, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises copper wire.
 3452. The system of claim 3441, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor.
 3453. The system of claim 3441, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 3454. The system of claim 3441, wherein at least the one elongated member is arranged in a series electrical configuration.
 3455. The system of claim 3441, wherein at least the one elongated member is arranged in a parallel electrical configuration.
 3456. The system of claim 3441, wherein at least the one elongated member is configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.
 3457. The system of claim 3441, further comprising a perforated tube disposed in the opening external to at least the one elongated member, wherein the perforated tube is configurable to remove vapor from the opening to control a pressure in the opening during use.
 3458. The system of claim 3441, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3459. The system of claim 3441, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3460. The system of claim 3441, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3461. The system of claim 3441, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3462. The system of claim 3441, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.
 3463. The system of claim 3441, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.
 3464. The system of claim 3441, wherein the heated section of the formation is substantially pyrolyzed.
 3465. The system of claim 3441, wherein the system is configured to heat a relatively permeable formation containing heavy hydrocarbons, and wherein the system comprises: at least one elongated member disposed within an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use; an oxidizing fluid source; a conduit disposed within the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to the opening during use; and wherein the oxidizing fluid is selected to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use; and wherein the system is configured to allow heat to transfer from at least the one elongated member to a section of the formation during use.
 3466. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: applying an electrical current to at least one elongated member to provide heat to at least a portion of the formation, wherein at least the one elongated member is disposed within an opening in the formation; providing an oxidizing fluid to at least the one elongated member to substantially inhibit carbon deposition on or proximate to at least the one elongated member; and allowing heat to transfer from at least the one elongated member to a section of the formation.
 3467. The method of claim 3466, wherein at least the one elongated member comprises a metal strip.
 3468. The method of claim 3466, wherein at least the one elongated member comprises a metal rod.
 3469. The method of claim 3466, wherein at least the one elongated member comprises stainless steel.
 3470. The method of claim 3466, further comprising supporting at least the one elongated member on a center support member.
 3471. The method of claim 3466, further comprising supporting at least the one elongated member on a center support member, wherein the center support member comprises a tube.
 3472. The method of claim 3466, further comprising electrically isolating at least the one elongated member with a centralizer.
 3473. The method of claim 3466, further comprising laterally spacing at least the one elongated member with a centralizer.
 3474. The method of claim 3466, further comprising electrically coupling at least the one elongated member in a series configuration.
 3475. The method of claim 3466, further comprising electrically coupling at least the one elongated member in a parallel configuration.
 3476. The method of claim 3466, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.
 3477. The method of claim 3466, further comprising determining a temperature distribution in at least the one elongated member using an electromagnetic signal provided to at least the one elongated member.
 3478. The method of claim 3466, further comprising monitoring the applied electrical current.
 3479. The method of claim 3466, further comprising monitoring a voltage applied to at least the one elongated member.
 3480. The method of claim 3466, further comprising monitoring a temperature in at least the one elongated member with at least one thermocouple.
 3481. The method of claim 3466, further comprising supporting at least the one elongated member on a center support member, wherein the center support member comprises openings, wherein providing the oxidizing fluid to at least the one elongated member comprises flowing the oxidizing fluid through the openings in the center support member.
 3482. The method of claim 3466, wherein providing the oxidizing fluid to at least the one elongated member comprises flowing the oxidizing fluid through orifices in a tube disposed in the opening proximate to at least the one elongated member.
 3483. The method of claim 3466, further comprising electrically coupling a lead-in conductor to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.
 3484. The method of claim 3466, further comprising electrically coupling a lead-in conductor to at least the one elongated member using a cold pin transition conductor.
 3485. The method of claim 3466, further comprising electrically coupling a lead-in conductor to at least the one elongated member using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.
 3486. The method of claim 3466, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.
 3487. The method of claim 3466, further comprising coupling an overburden casing to the opening, wherein the overburden casing comprises steel.
 3488. The method of claim 3466, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in cement.
 3489. The method of claim 3466, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.
 3490. The method of claim 3466, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with the packing material.
 3491. The method of claim 3466, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.
 3492. An in situ method for heating a relatively permeable formation containing heavy hydrocarbons, comprising: oxidizing a fuel fluid in a heater; providing at least a portion of the oxidized fuel fluid into a conduit disposed in an opening of the formation; allowing heat to transfer from the oxidized fuel fluid to a section of the formation; and allowing additional heat to transfer from an electric heater disposed in the opening to the section of the formation, wherein heat is allowed to transfer substantially uniformly along a length of the opening.
 3493. The method of claim 3492, wherein providing at least the portion of the oxidized fuel fluid into the opening comprises flowing the oxidized fuel fluid through a perforated conduit disposed in the opening.
 3494. The method of claim 3492, wherein providing at least the portion of the oxidized fuel fluid into the opening comprises flowing the oxidized fuel fluid through a perforated conduit disposed in the opening, the method further comprising removing an exhaust fluid through the opening.
 3495. The method of claim 3492, further comprising initiating oxidation of the fuel fluid in the heater with a flame.
 3496. The method of claim 3492, further comprising removing the oxidized fuel fluid through the conduit.
 3497. The method of claim 3492, further comprising removing the oxidized fuel fluid through the conduit and providing the removed oxidized fuel fluid to at least one additional heater disposed in the formation.
 3498. The method of claim 3492, wherein the conduit comprises an insulator disposed on a surface of the conduit, the method further comprising tapering a thickness of the insulator such that heat is allowed to transfer substantially uniformly along a length of the conduit.
 3499. The method of claim 3492, wherein the electric heater is an insulated conductor.
 3500. The method of claim 3492, wherein the electric heater is a conductor disposed in the conduit.
 3501. The method of claim 3492, wherein the electric heater is an elongated conductive member.
 3502. A system configured to heat a relatively permeable formation containing heavy hydrocarbons, comprising: one or more heat sources disposed within one or more open wellbores in the formation, wherein the one or more heat sources are configured to provide heat to at least a portion of the formation during use; and wherein the system is configured to allow heat to transfer from the one or more heat sources to a selected section of the formation during use.
 3503. The system of claim 3502, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 3504. The system of claim 3502, wherein the one or more heat sources comprise electrical heaters.
 3505. The system of claim 3502, wherein the one or more heat sources comprise surface burners.
 3506. The system of claim 3502, wherein the one or more heat sources comprise flameless distributed combustors.
 3507. The system of claim 3502, wherein the one or more heat sources comprise natural distributed combustors.
 3508. The system of claim 3502, wherein the one or more open wellbores comprise a diameter of at least approximately 5 cm.
 3509. The system of claim 3502, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation.
 3510. The system of claim 3502, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3511. The system of claim 3502, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3512. The system of claim 3502, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the at least one of the one or more open wellbores.
 3513. The system of claim 3502, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the at least one of the one or more open wellbores, and wherein the packing material is configured to substantially inhibit a flow of fluid between at least one of the one or more open wellbores and the overburden casing during use.
 3514. The system of claim 3502, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the at least one of the one or more open wellbores, and wherein the packing material comprises cement.
 3515. The system of claim 3502, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.
 3516. The system of claim 3502, further comprising a valve coupled to at least one of the one or more heat sources configured to control pressure within at least a majority of the selected section of the formation.
 3517. The system of claim 3502, further comprising a valve coupled to a production well configured to control a pressure within at least a majority of the selected section of the formation.
 3518. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation, wherein the one or more heat sources are disposed within one or more open wellbores in the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing a mixture from the formation.
 3519. The method of claim 3518, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 3520. The method of claim 3518, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range with a lower pyrolysis temperature of about 250° C. and an upper pyrolysis temperature of about 400° C.
 3521. The method of claim 3518, wherein the one or more heat sources comprise electrical heaters.
 3522. The method of claim 3518, wherein the one or more heat sources comprise surface burners.
 3523. The method of claim 3518, wherein the one or more heat sources comprise flameless distributed combustors.
 3524. The method of claim 3518, wherein the one or more heat sources comprise natural distributed combustors.
 3525. The method of claim 3518, wherein the one or more heat sources are suspended within the one or more open wellbores.
 3526. The method of claim 3518, wherein a tube is disposed in at least one of the one or more open wellbores proximate to the heat source, the method further comprising flowing a substantially constant amount of fluid into at least one of the one or more open wellbores through critical flow orifices in the tube.
 3527. The method of claim 3518, wherein a perforated tube is disposed in at least one of the one or more open wellbores proximate to the heat source, the method further comprising flowing a corrosion inhibiting fluid into at least one of the open wellbores through the perforated tube.
 3528. The method of claim 3518, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation.
 3529. The method of claim 3518, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.
 3530. The method of claim 3518, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.
 3531. The method of claim 3518, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the at least one of the one or more open wellbores.
 3532. The method of claim 3518, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the at least one of the one or more open wellbores and the overburden casing with a packing material.
 3533. The method of claim 3518, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.
 3534. The method of claim 3518, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 3535. The method of claim 3518, further comprising controlling a pressure with the wellbore.
 3536. The method of claim 3518, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to at least one of the one or more heat sources.
 3537. The method of claim 3518, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to a production well located in the formation.
 3538. The method of claim 3518, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.
 3539. The method of claim 3518, wherein providing heat from the one or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 3540. The method of claim 3518, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.
 3541. The method of claim 3518, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.
 3542. The method of claim 3518, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 3543. The method of claim 3518, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3544. The method of claim 3518, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.
 3545. The method of claim 3518, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3546. The method of claim 3518, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3547. The method of claim 3518, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3548. The method of claim 3518, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3549. The method of claim 3518, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3550. The method of claim 3518, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3551. The method of claim 3518, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3552. The method of claim 3518, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 3553. The method of claim 3518, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3554. The method of claim 3518, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 3555. The method of claim 3518, further comprising controlling a pressure within at least a majority of the selected section of the formation.
 3556. The method of claim 3518, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.
 3557. The method of claim 3518, further comprising controlling formation conditions such that the produced mixture comprises a partial pressure of H₂ within the mixture greater than about 0.5 bars.
 3558. The method of claim 3557, wherein the partial pressure of H₂ is measured when the mixture is at a production well.
 3559. The method of claim 3518, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.
 3560. The method of claim 3518, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 3561. The method of claim 3518, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 3562. The method of claim 3518, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 3563. The method of claim 3518, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for the production well.
 3564. The method of claim 3563, wherein at least about 20 heat sources are disposed in the formation for each production well.
 3565. The method of claim 3518, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 3566. The method of claim 3518, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 3567. The method of claim 3518, further comprising separating the produced mixture into a gas stream and a liquid stream.
 3568. The method of claim 3518, further comprising separating the produced mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 3569. The method of claim 3518, wherein the produced mixture comprises H₂S, the method further comprising separating a portion of the H₂S from non-condensable hydrocarbons.
 3570. The method of claim 3518, wherein the produced mixture comprises CO₂, the method further comprising separating a portion of the CO₂ from non-condensable hydrocarbons.
 3571. The method of claim 3518, wherein the mixture is produced from a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.
 3572. The method of claim 3518, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 3573. The method of claim 3518, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture, wherein the mixture comprises a large non-condensable hydrocarbon gas component and H₂.
 3574. The method of claim 3518, wherein the selected section is heated to a minimum pyrolysis temperature of about 270° C.
 3575. The method of claim 3518, further comprising maintaining the pressure within the formation above about 2.0 bars absolute to inhibit production of fluids having carbon numbers above
 25. 3576. The method of claim 3518, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an amount of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to increase production of condensable hydrocarbons, and wherein the pressure is increased to increase production of non-condensable hydrocarbons.
 3577. The method of claim 3518, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an API gravity of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.
 3578. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, the mixture, comprising: non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5; and wherein a weight ratio of the hydrocarbons having carbon numbers from 2 through 4, to methane, in the mixture is greater than approximately
 1. 3579. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 3580. The mixture of claim 3578, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3581. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3582. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3583. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3584. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3585. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3586. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3587. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise cycloalkanes.
 3588. The mixture of claim 3578, wherein the non-condensable hydrocarbons further comprise hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons, and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.
 3589. The mixture of claim 3578, further comprising ammonia, wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3590. The mixture of claim 3578, further comprising ammonia, wherein the ammonia is used to produce fertilizer.
 3591. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein less than about 15 weight % of the condensable hydrocarbons have a carbon number greater than approximately
 25. 3592. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein the condensable hydrocarbons comprise olefins, and wherein about 0.1% to about 5% by weight of the condensable hydrocarbons comprises olefins.
 3593. The mixture of claim 3578, further comprising condensable hydrocarbons, wherein the condensable hydrocarbons comprises olefins, and wherein about 0.1% to about 2.5% by weight of the condensable hydrocarbons comprises olefins.
 3594. The mixture of claim 3578, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.
 3595. The mixture of claim 3578, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.
 3596. The mixture of claim 3578, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.3.
 3597. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, the mixture comprising: non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5, wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1; condensable hydrocarbons; wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons comprises nitrogen; wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons comprises oxygen; and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons comprises sulfur.
 3598. The mixture of claim 3597, further comprising ammonia, wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3599. The mixture of claim 3597, wherein less than about 5 weight % of the condensable hydrocarbons have a carbon number greater than approximately
 25. 3600. The mixture of claim 3597, wherein the condensable hydrocarbons comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 3601. The mixture of claim 3597, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3602. The mixture of claim 3597, wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3603. The mixture of claim 3597, wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3604. The mixture of claim 3597, wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3605. The mixture of claim 3597, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3606. The mixture of claim 3597, wherein the non-condensable hydrocarbons comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.
 3607. The mixture of claim 3597, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3608. The mixture of claim 3597, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.
 3609. The mixture of claim 3597, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.
 3610. The mixture of claim 3597, wherein the non-condensable hydrocarbons comprise 1H₂, and wherein greater than about 15% by weight of the mixture comprises H₂.
 3611. The mixture of claim 3597, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater, than about 0.3.
 3612. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, the mixture comprising: non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5, wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1; and ammonia, wherein greater than about 0.5% by weight of the mixture comprises ammonia.
 3613. The mixture of claim 3612, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 3614. The mixture of claim 3612, wherein the non-condensable hydrocarbons further comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3615. The mixture of claim 3612, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3616. The mixture of claim 3612, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3617. The mixture of claim 3612, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3618. The mixture of claim 3612, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3619. The mixture of claim 3612, wherein the condensable hydrocarbons further comprise multi-aromatic rings, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3620. The mixture of claim 3612, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3621. The mixture of claim 3612, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3622. The mixture of claim 3612, wherein the non-condensable hydrocarbons further comprise hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons, and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.
 3623. The mixture of claim 3612, wherein the produced mixture further comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3624. The mixture of claim 3612, wherein the produced mixture further comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 3625. The mixture of claim 3612, wherein the condensable hydrocarbons comprise hydrocarbons having a carbon number of greater than approximately 25, and wherein less than about 15 weight % of the hydrocarbons in the mixture have a carbon number greater than approximately
 25. 3626. The mixture of claim 3612, wherein the non-condensable hydrocarbons further comprise H₂, and wherein greater than about 5% by weight of the mixture comprises H₂.
 3627. The mixture of claim 3612, wherein the non-condensable hydrocarbons further comprise H₂, and wherein greater than about 15% by weight of the mixture comprises H₂.
 3628. The mixture of claim 3612, wherein the non-condensable hydrocarbons further comprise hydrocarbons having carbon numbers of greater than 2, wherein a weight ratio of hydrocarbons having carbon numbers greater than 2, to methane, is greater than about 0.3.
 3629. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, the mixture comprising: non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5, wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1; and condensable hydrocarbons comprising olefins, wherein less than about 10% by weight of the condensable hydrocarbons comprises olefins.
 3630. The mixture of claim 3629, wherein the non-condensable hydrocarbons further comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3631. The mixture of claim 3629, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3632. The mixture of claim 3629, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3633. The mixture of claim 3629, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3634. The mixture of claim 3629, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3635. The mixture of claim 3629, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3636. The mixture of claim 3629, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3637. The mixture of claim 3629, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3638. The mixture of claim 3629, wherein the non-condensable hydrocarbons further comprise hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.
 3639. The mixture of claim 3629, wherein the produced mixture further comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3640. The mixture of claim 3629, wherein the produced mixture further comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 3641. The mixture of claim 3629, wherein the condensable hydrocarbons further comprise hydrocarbons having a carbon number of greater than approximately 25, and wherein less than about 15% by weight of the hydrocarbons have a carbon number greater than approximately
 25. 3642. The mixture of claim 3629, wherein about 0.1% to about 5% by weight of the condensable component comprises olefins.
 3643. The mixture of claim 3629, wherein about 0.1% to about 2% by weight of the condensable component comprises olefins.
 3644. The mixture of claim 3629, wherein the non-condensable hydrocarbons further comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.
 3645. The mixture of claim 3629, wherein the non-condensable hydrocarbons further comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.
 3646. The mixture of claim 3629, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.3.
 3647. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, comprising: condensable hydrocarbons, wherein less than about 15 weight % of the condensable hydrocarbons have a carbon number greater than
 25. 3648. The mixture of claim 3647, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately
 1. 3649. The mixture of claim 3647, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 3650. The mixture of claim 3647, further comprising non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3651. The mixture of claim 3647, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3652. The mixture of claim 3647, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3653. The mixture of claim 3647, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3654. The mixture of claim 3647, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3655. The mixture of claim 3647, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3656. The mixture of claim 3647, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3657. The mixture of claim 3647, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3658. The mixture of claim 3647, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.
 3659. The mixture of claim 3647, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3660. The mixture of claim 3647, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.
 3661. The mixture of claim 3647, wherein the condensable hydrocarbons further comprises olefins, and wherein less than about 10% by weight of the condensable hydrocarbons comprises olefins.
 3662. The mixture of claim 3647, wherein the condensable hydrocarbons further comprises olefins, and wherein about 0.1% to about 5% by weight of the condensable hydrocarbons comprises olefins.
 3663. The mixture of claim 3647, wherein the condensable hydrocarbons further comprises olefins, and wherein about 0.1% to about 2% by weight of the condensable hydrocarbons comprises olefins.
 3664. The mixture of claim 3647, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.
 3665. The mixture of claim 3647, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.
 3666. The mixture of claim 3647, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.3.
 3667. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, comprising: condensable hydrocarbons, wherein less than about 15% by weight of the condensable hydrocarbons have a carbon number greater than about 25; wherein less than about 1% by weight of the condensable hydrocarbons, when calculated on an atomic basis, is nitrogen; wherein less than about 1% by weight of the condensable hydrocarbons, when calculated on an atomic basis, is oxygen; and wherein less than about 5% by weight of the condensable hydrocarbons, when calculated on an atomic basis, is sulfur.
 3668. The mixture of claim 3667, further comprising non-condensable hydrocarbons, wherein the non-condensable component comprises hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately
 1. 3669. The mixture of claim 3667, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 3670. The mixture of claim 3667, further comprising non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3671. The mixture of claim 3667, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3672. The mixture of claim 3667, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3673. The mixture of claim 3667, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3674. The mixture of claim 3667, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3675. The mixture of claim 3667, further comprising non-condensable hydrocarbons, and wherein the non-condensable hydrocarbons comprise hydrogen, and wherein greater than about 10% by volume and less than about 80% by volume of the non-condensable component comprises hydrogen.
 3676. The mixture of claim 3667, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3677. The mixture of claim 3667, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.
 3678. The mixture of claim 3667, wherein the condensable component further comprises olefins, and wherein about 0.1% to about 5% by weight of the condensable component comprises olefins.
 3679. The mixture of claim 3667, wherein the condensable component further comprises olefins, and wherein about 0.1% to about 2.5% by weight of the condensable component comprises olefins.
 3680. The mixture of claim 3667, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.
 3681. The mixture of claim 3667, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.
 3682. The mixture of claim 3667, further comprising non-condensable hydrocarbons, wherein a weight ratio of compounds within the non-condensable hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.3.
 3683. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, comprising: condensable hydrocarbons, wherein less than about 15% by weight of the condensable hydrocarbons have a carbon number greater than 20; and wherein the condensable hydrocarbons comprise olefins, wherein an olefin content of the condensable component is less than about 10% by weight of the condensable component.
 3684. The mixture of claim 3683, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately
 1. 3685. The mixture of claim 3683, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 3686. The mixture of claim 3683, further comprising non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3687. The mixture of claim 3683, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3688. The mixture of claim 3683, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3689. The mixture of claim 3683, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3690. The mixture of claim 3683, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3691. The mixture of claim 3683, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3692. The mixture of claim 3683, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3693. The mixture of claim 3683, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3694. The mixture of claim 3683, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprises hydrogen, and wherein the hydrogen is about 10% by volume to about 80% by volume of the non-condensable hydrocarbons.
 3695. The mixture of claim 3683, further comprising ammonia, wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3696. The mixture of claim 3683, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.
 3697. The mixture of claim 3683, wherein about 0.1% to about 5% by weight of the condensable component comprises olefins.
 3698. The mixture of claim 3683, wherein about 0.1% to about 2% by weight of the condensable component comprises olefins.
 3699. The mixture of claim 3683, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.
 3700. The mixture of claim 3683, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons Comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.
 3701. The mixture of claim 3683, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 0.3.
 3702. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, comprising: condensable hydrocarbons, wherein less than about 5% by weight of the condensable hydrocarbons comprises hydrocarbons having a carbon number greater than about 25; and wherein the condensable hydrocarbons further comprise aromatic compounds, wherein more than about 20% by weight of the condensable hydrocarbons comprises aromatic compounds.
 3703. The mixture of claim 3702, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately
 1. 3704. The mixture of claim 3702, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 3705. The mixture of claim 3702, further comprising non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3706. The mixture of claim 3702, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3707. The mixture of claim 3702, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3708. The mixture of claim 3702, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3709. The mixture of claim 3702, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3710. The mixture of claim 3702, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3711. The mixture of claim 3702, wherein the condensable hydrocarbons comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3712. The mixture of claim 3702, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrogen, and wherein the hydrogen is greater than about 10% by volume and less than about 80% by volume of the non-condensable hydrocarbons.
 3713. The mixture of claim 3702, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3714. The mixture of claim 3702, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.
 3715. The mixture of claim 3702, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% to about 5% by weight of the condensable hydrocarbons comprises olefins.
 3716. The mixture of claim 3702, wherein the condensable hydrocarbons further comprises olefins, and wherein about 0.1% to about 2% by weight of the condensable hydrocarbons comprises olefins.
 3717. The mixture of claim 3702, wherein the condensable hydrocarbons further comprises multi-ring aromatic compounds, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatic compounds.
 3718. The mixture of claim 3702, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.
 3719. The mixture of claim 3702, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.
 3720. The mixture of claim 3702, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprises hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 0.3.
 3721. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, comprising: non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than about 5, wherein a weight ratio of the hydrocarbons having carbon number from 2 through 4, to methane, in the mixture is greater than approximately 1; wherein the non-condensable hydrocarbons further comprise H₂, wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂; and condensable hydrocarbons, comprising: olefins, wherein less than about 10% by weight of the condensable hydrocarbons comprises olefins; and aromatic compounds, wherein greater than about 20% by weight of the condensable hydrocarbons comprises aromatic compounds.
 3722. The mixture of claim 3721, wherein the non-condensable hydrocarbons further comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.0011 to about 0.15.
 3723. The mixture of claim 3721, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3724. The mixture of claim 3721, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3725. The mixture of claim 3721, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3726. The mixture of claim 3721, wherein the condensable hydrocarbons comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3727. The mixture of claim 3721, wherein the condensable hydrocarbons comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3728. The mixture of claim 3721, wherein the condensable hydrocarbons comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3729. The mixture of claim 3721, wherein the non-condensable hydrocarbons further comprise hydrogen, and wherein the hydrogen is greater than about 10% by volume and less than about 80% by volume of the non-condensable hydrocarbons.
 3730. The mixture of claim 3721, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3731. The mixture of claim 3721, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.
 3732. The mixture of claim 3721, wherein the condensable hydrocarbons further comprise hydrocarbons having a carbon number of greater than approximately 25, wherein less than about 15% by weight of the hydrocarbons have a carbon number greater than approximately
 25. 3733. The mixture of claim 3721, wherein about 0.1%to about 5%by weight of the condensable hydrocarbons comprises olefins.
 3734. The mixture of claim 3721, wherein about 0.1% to about 2% by weight of the condensable hydrocarbons comprises olefins.
 3735. The mixture of claim 3721, wherein the mixture comprises hydrocarbons having greater than about 2 carbon atoms, and wherein the weight ratio of hydrocarbons having greater than about 2 carbon atoms to methane is greater than about 0.3.
 3736. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, comprising: condensable hydrocarbons, wherein less than about 5% by weight of the condensable hydrocarbons comprises hydrocarbons having a carbon number greater than about 25; wherein the condensable hydrocarbons further comprise: olefins, wherein less than about 10% by weight of the condensable hydrocarbons comprises olefins; and aromatic compounds, wherein greater than about 30% by weight of the condensable hydrocarbons comprises aromatic compounds; and non-condensable hydrocarbons comprising H₂, wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.
 3737. The mixture of claim 3736, wherein the non-condensable hydrocarbons further comprises hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately
 1. 3738. The mixture of claim 3736, wherein the non-condensable hydrocarbons comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3739. The mixture of claim 3736, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3740. The mixture of claim 3736, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3741. The mixture of claim 3736, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3742. The mixture of claim 3736, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3743. The mixture of claim 3736, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3744. The mixture of claim 3736, wherein the condensable hydrocarbons comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3745. The mixture of claim 3736, wherein greater than about 10% by volume and less than about 80% by volume of the non-condensable hydrocarbons is hydrogen.
 3746. The mixture of claim 3736, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3747. The mixture of claim 3736, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.
 3748. The mixture of claim 3736, wherein about 0.1% to about 5% by weight of the condensable hydrocarbons comprises olefins.
 3749. The mixture of claim 3736, wherein about 0.1% to about 2% by weight of the condensable hydrocarbons comprises olefins.
 3750. The mixture of claim 3736, wherein the mixture comprises hydrocarbons having greater than about 2 carbon atoms, and wherein the weight ratio of hydrocarbons having greater than about 2 carbon atoms to methane is greater than about 0.3.
 3751. A mixture of condensable hydrocarbons produced from a portion of a relatively permeable formation containing heavy hydrocarbons, comprising: olefins, wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons comprises olefins; and asphaltenes, wherein less than about 0.1% by weight of the condensable hydrocarbons comprises asphaltenes.
 3752. The mixture of claim 3751, wherein the condensable hydrocarbons further comprises hydrocarbons having a carbon number of greater than approximately 25, and wherein less than about 15 weight % of the hydrocarbons in the mixture have a carbon number greater than approximately
 25. 3753. The mixture of claim 3751, wherein about 0.1% by weight to about 5% by weight of the condensable hydrocarbons comprises olefins.
 3754. The mixture of claim 3751, wherein the condensable hydrocarbons further comprises non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3755. The mixture of claim 3751, wherein the condensable hydrocarbons further comprises nitrogen, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3756. The mixture of claim 3751, wherein the condensable hydrocarbons further comprises oxygen, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3757. The mixture of claim 3751, wherein the condensable hydrocarbons further comprises sulfur, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3758. The mixture of claim 3751, wherein the condensable hydrocarbons further comprises aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3759. The mixture of claim 3751, wherein the condensable hydrocarbons further comprises multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3760. The mixture of claim 3751, wherein the condensable hydrocarbons further comprises cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3761. The mixture of claim 3751, wherein the condensable hydrocarbons comprises non-condensable hydrocarbons, and wherein the non-condensable hydrocarbons comprise hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.
 3762. The mixture of claim 3751, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3763. The mixture of claim 3751, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.
 3764. The mixture of claim 3751, wherein about 0.1% by weight to about 2% by weight of the condensable hydrocarbons comprises olefins.
 3765. A mixture of condensable hydrocarbons produced from a portion of a relatively permeable formation containing heavy hydrocarbons, comprising: olefins, wherein about 0.1% by weight to about 2% by weight of the condensable hydrocarbons comprises olefins; multi-ring aromatics, wherein less than about 4% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3766. The mixture of claim 3765, further comprising hydrocarbons having a carbon number of greater than approximately 25, wherein less than about 5 weight % of the hydrocarbons in the mixture have a carbon number greater than approximately
 25. 3767. The mixture of claim 3765, wherein the condensable hydrocarbons further comprises nitrogen, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3768. The mixture of claim 3765, wherein the condensable hydrocarbons further comprises oxygen, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3769. The mixture of claim 3765, wherein the condensable hydrocarbons further comprises sulfur, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3770. The mixture of claim 3765, wherein the condensable hydrocarbons further comprises aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3771. The mixture of claim 3765, wherein the condensable hydrocarbons further comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3772. The mixture of claim 3765, wherein the condensable hydrocarbons further comprises cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3773. The mixture of claim 3765, further comprising ammonia, wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3774. The mixture of claim 3765, further comprising ammonia, wherein the ammonia is used to produce fertilizer.
 3775. A mixture produced from a portion of a relatively permeable formation containing heavy hydrocarbons, comprising: non-condensable hydrocarbons and H₂, wherein greater than about 10% by volume of the non-condensable hydrocarbons and H₂ comprises H₂; ammonia and water, wherein greater than about 0.5% by weight of the mixture comprises ammonia; and condensable hydrocarbons.
 3776. The mixture of claim 3775, wherein the non-condensable hydrocarbons further comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of the hydrocarbons having carbon numbers from 2 through 4 to methane, in the mixture is greater than approximately
 1. 3777. The mixture of claim 3775, wherein greater than about 0.1% by weight of the condensable hydrocarbons are olefins, and wherein less than about 15% by weight of the condensable hydrocarbons are olefins.
 3778. The mixture of claim 3775, wherein the non-condensable hydrocarbons further comprise ethene and ethane, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is greater than about 0.001, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15.
 3779. The mixture of claim 3775, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3780. The mixture of claim 3775, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3781. The mixture of claim 3775, wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3782. The mixture of claim 3775, wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3783. The mixture of claim 3775, wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3784. The mixture of claim 3775, wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.
 3785. The mixture of claim 3775, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3786. The mixture of claim 3775, wherein the H₂ is less than about 80% by volume of the non-condensable hydrocarbons and H₂.
 3787. The mixture of claim 3775, wherein the condensable hydrocarbons further comprise sulfur containing compounds.
 3788. The mixture of claim 3775, wherein the ammonia is used to produce fertilizer.
 3789. The mixture of claim 3775, wherein less than about 5% of the condensable hydrocarbons have carbon numbers greater than
 25. 3790. The mixture of claim 3775, wherein the condensable hydrocarbons comprise olefins, wherein greater than about about 0.001% by weight of the condensable hydrocarbons comprise olefins, and wherein less than about 15% by weight of the condensable hydrocarbons comprise olefins.
 3791. The mixture of claim 3775, wherein the condensable hydrocarbons comprise olefins, wherein greater than about about 0.001% by weight of the condensable hydrocarbons comprise olefins, and wherein less than about 10% by weight of the condensable hydrocarbons comprise olefins.
 3792. The mixture of claim 3775, wherein the condensable hydrocarbons further comprise nitrogen containing compounds.
 3793. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 3794. The method of claim 3793, wherein three or more of the heat sources are located in the formation in a plurality of the units, and wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units.
 3795. The method of claim 3793, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, and wherein a ratio of heat sources in the repetitive pattern of units to production wells in the repetitive pattern is less than approximately
 5. 3796. The method of claim 3793, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, wherein three or more production wells are located within an area defined by the plurality of units, wherein the three or more production wells are located in the formation in a unit of production wells, and wherein the unit of production wells comprises a triangular pattern.
 3797. The method of claim 3793, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, wherein three or more injection wells are located within an area defined by the plurality of units, wherein the three or more injection wells are located in the formation in a unit of injection wells, and wherein the unit of injection wells comprises a triangular pattern.
 3798. The method of claim 3793, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, wherein three or more production wells and three or more injection wells are located within an area defined by the plurality of units, wherein the three or more production wells are located in the formation in a unit of production wells, wherein the unit of production wells comprises a first triangular pattern, wherein the three or more injection wells are located in the formation in a unit of injection wells, wherein the unit of injection wells comprises a second triangular pattern, and wherein the first triangular pattern is substantially different than the second triangular pattern.
 3799. The method of claim 3793, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, wherein three or more monitoring wells are located within an area defined by the plurality of units, wherein the three or more monitoring wells are located in the formation in a unit of monitoring wells, and wherein the unit of monitoring wells comprises a triangular pattern.
 3800. The method of claim 3793, wherein a production well is located in an area defined by the unit of heat sources.
 3801. The method of claim 3793, wherein three or more of the heat sources are located in the formation in a first unit and a second unit, wherein the first unit is adjacent to the second unit, and wherein the first unit is inverted with respect to the second unit.
 3802. The method of claim 3793, wherein a distance between each of the heat sources in the unit of heat sources varies by less than about 20%.
 3803. The method of claim 3793, wherein a distance between each of the heat sources in the unit of heat sources is approximately equal.
 3804. The method of claim 3793, wherein providing heat from three or more heat sources comprises substantially uniformly providing heat to at least the portion of the formation.
 3805. The method of claim 3793, wherein the heated portion comprises a substantially uniform temperature distribution.
 3806. The method of claim 3793, wherein the heated portion comprises a substantially uniform temperature distribution, and wherein a difference between a highest temperature in the heated portion and a lowest temperature in the heated portion comprises less than about 200° C.
 3807. The method of claim 3793, wherein a temperature at an outer lateral boundary of the triangular pattern and a temperature at a center of the triangular pattern are approximately equal.
 3808. The method of claim 3793, wherein a temperature at an outer lateral boundary of the triangular pattern and a temperature at a center of the triangular pattern increase substantially linearly after an initial period of time, and wherein the initial period of time comprises less than approximately 3 months.
 3809. The method of claim 3793, wherein a time required to increase an average temperature of the heated portion to a selected temperature with the triangular pattern of heat sources is substantially less than a time required to increase the average temperature of the heated portion to the selected temperature with a hexagonal pattern of heat sources, and wherein a space between each of the heat sources in the triangular pattern is approximately equal to a space between each of the heat sources in the hexagonal pattern.
 3810. The method of claim 3793, wherein a time required to increase a temperature at a coldest point within the heated portion to a selected temperature with the triangular pattern of heat sources is substantially less than a time required to increase a temperature at the coldest point within the heated portion to the selected temperature with a hexagonal pattern of heat sources, and wherein a space between each of the heat sources in the triangular pattern is approximately equal to a space between each of the heat sources in the hexagonal pattern.
 3811. The method of claim 3793, wherein a time required to increase a temperature at a coldest point within the heated portion to a selected temperature with the triangular pattern of heat sources is substantially less than a time required to increase a temperature at the coldest point within the heated portion to the selected temperature with a hexagonal pattern of heat sources, and wherein a number of heat sources per unit area in the triangular pattern is equal to the number of heat sources per unit are in the hexagonal pattern of heat sources.
 3812. The method of claim 3793, wherein a time required to increase a temperature at a coldest point within the heated portion to a selected temperature with the triangular pattern of heat sources is substantially equal to a time required to increase a temperature at the coldest point within the heated portion to the selected temperature with a hexagonal pattern of heat sources, and wherein a space between each of the heat sources in the triangular pattern is approximately 5 m greater than a space between each of the heat sources in the hexagonal pattern.
 3813. The method of claim 3793, wherein providing heat from three or more heat sources to at least the portion of formation comprises: heating a selected volume (V) of the relatively permeable formation containing heavy hydrocarbons from three or more of the heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein heat from three or more of the heat sources pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 3814. The method of claim 3793, wherein three or more of the heat sources comprise electrical heaters.
 3815. The method of claim 3793, wherein three or more of the heat sources comprise surface burners.
 3816. The method of claim 3793, wherein three or more of the heat sources comprise flameless distributed combustors.
 3817. The method of claim 3793, wherein three or more of the heat sources comprise natural distributed combustors.
 3818. The method of claim 3793, further comprising: allowing the heat to transfer from three or more of the heat sources to a selected section of the formation such that heat from three or more of the heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation; and producing a mixture of fluids from the formation.
 3819. The method of claim 3818, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 3820. The method of claim 3818, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0° C. per day during pyrolysis.
 3821. The method of claim 3818, wherein allowing the heat to transfer from three or more of the heat sources to the selected section comprises transferring heat substantially by conduction.
 3822. The method of claim 3818, wherein the produced mixture comprises an API gravity of at least 25°.
 3823. The method of claim 3818, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.
 3824. The method of claim 3818, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.
 3825. The method of claim 3818, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.
 3826. The method of claim 3818, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.
 3827. The method of claim 3818, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.
 3828. The method of claim 3818, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.
 3829. The method of claim 3818, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.
 3830. The method of claim 3818, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.1% by weight of the condensable hydrocarbons are asphaltenes.
 3831. The method of claim 3818, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.
 3832. The method of claim 3818, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.
 3833. The method of claim 3818, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.
 3834. The method of claim 3818, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.
 3835. The method of claim 3818, further comprising controlling formation conditions to produce a mixture of hydrocarbon fluids and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 2.0 bars absolute.
 3836. The method of claim 3818, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about
 25. 3837. The method of claim 3818, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.
 3838. The method of claim 3818, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 3839. The method of claim 3818, further comprising: producing hydrogen from the formation; and hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 3840. The method of claim 3818, wherein producing the mixture comprises producing the mixture in a production well, wherein at least about 7 heat sources are disposed in the formation for each production well.
 3841. The method of claim 3840, wherein at least about 20 heat sources are disposed in the formation for each production well.
 3842. The method of claim 3818, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 3843. The method of claim 3818, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 3844. A method for in situ production of synthesis gas from a relatively permeable formation containing heavy hydrocarbons, comprising: heating a section of the formation to a temperature sufficient to allow synthesis gas generation, wherein a permeability of the section is substantially uniform; providing a synthesis gas generating fluid to the section to generate synthesis gas; and removing synthesis gas from the formation.
 3845. The method of claim 3844, wherein the temperature sufficient to allow synthesis gas generation ranges from approximately 400° C. to approximately 1200° C.
 3846. The method of claim 3844, further comprising heating the section when providing the synthesis gas generating fluid to inhibit temperature decrease in the section due to synthesis gas generation.
 3847. The method of claim 3844, wherein heating the section comprises convecting an oxidizing fluid into a portion of the section, wherein the temperature within the section is above a temperature sufficient to support oxidation of carbon within the section with the oxidizing fluid, and reacting the oxidizing fluid with carbon in the section to generate heat within the section.
 3848. The method of claim 3847, wherein the oxidizing fluid comprises air.
 3849. The method of claim 3848, wherein an amount of the oxidizing fluid convected into the section is configured to inhibit formation of oxides of nitrogen by maintaining a reaction temperature below a temperature sufficient to produce oxides of nitrogen compounds.
 3850. The method of claim 3844, wherein heating the section comprises diffusing an oxidizing fluid to reaction zones adjacent to wellbores within the formation, oxidizing carbon within the reaction zone to generate heat, and transferring the heat to the section.
 3851. The method of claim 3844, wherein heating the section comprises heating the section by transfer of heat from one or more of electrical heaters.
 3852. The method of claim 3844, wherein heating the section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to the section comprises introducing steam into the section to heat the formation and to generate synthesis gas.
 3853. The method of claim 3844, further comprising controlling the heating of the section and provision of the synthesis gas generating fluid to maintain a temperature within the section above the temperature sufficient to generate synthesis gas.
 3854. The method of claim 3844, further comprising: monitoring a composition of the produced synthesis gas; and controlling heating of the section and provision of the synthesis gas generating fluid to maintain the composition of the produced synthesis gas within a selected range.
 3855. The method of claim 3854, wherein the selected range comprises a ratio of H₂ to CO of about 2:1.
 3856. The method of claim 3844, wherein the synthesis gas generating fluid comprises liquid water.
 3857. The method of claim 3844, wherein the synthesis gas generating fluid comprises steam.
 3858. The method of claim 3844, wherein the synthesis gas generating fluid comprises water and carbon dioxide, and wherein the carbon dioxide inhibits production of carbon dioxide from hydrocarbon containing material within the section.
 3859. The method of claim 3858, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 3860. The method of claim 3844, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 3861. The method of claim 3860, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 3862. The method of claim 3844, wherein providing the synthesis gas generating fluid to the section comprises raising a water table of the formation to allow water to flow into the section.
 3863. The method of claim 3844, wherein the synthesis gas is removed from a producer well equipped with a heating source, and wherein a portion of the heating source adjacent to a synthesis gas producing zone operates at a substantially constant temperature to promote production of the synthesis gas wherein the synthesis gas has a selected composition.
 3864. The method of claim 3863, wherein the substantially constant temperature is about 700° C., and wherein the selected composition has a H₂ to CO ratio of about 2:1.
 3865. The method of claim 3844, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within the section to increase a H₂ concentration of the generated synthesis gas.
 3866. The method of claim 3844, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within the section to increase an energy content of the synthesis gas removed from the formation.
 3867. The method of claim 3844, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.
 3868. The method of claim 3844, further comprising generating electricity from the synthesis gas using a fuel cell.
 3869. The method of claim 3844, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.
 3870. The method of claim 3844, further comprising using a portion of the synthesis gas as a combustion fuel to heat the formation.
 3871. The method of claim 3844, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.
 3872. The method of claim 3844, further comprising converting at least a portion of the produced synthesis gas to methanol.
 3873. The method of claim 3844, further comprising converting at least a portion of the produced synthesis gas to gasoline.
 3874. The method of claim 3844, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.
 3875. The method of claim 3844, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 3876. The method of claim 3844, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 3877. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to increase a temperature of the portion to a temperature sufficient to allow synthesis gas generation; providing a synthesis gas generating fluid to at least the portion of the selected section, wherein the synthesis gas generating fluid comprises carbon dioxide; obtaining a portion of the carbon dioxide of the synthesis gas generating fluid from the formation; and producing synthesis gas from the formation.
 3878. The method of claim 3877, wherein the temperature sufficient to allow synthesis gas generation is within a range from about 400° C. to about 1200° C.
 3879. The method of claim 3877, further comprising using a second portion of the separated carbon dioxide as a flooding agent to produce hydrocarbon bed methane from a relatively permeable formation containing heavy hydrocarbons.
 3880. The method of claim 3879, wherein the relatively permeable formation containing heavy hydrocarbons is a deep relatively permeable formation containing heavy hydrocarbons over 760 m below ground surface.
 3881. The method of claim 3879, wherein the relatively permeable formation containing heavy hydrocarbons adsorbs some of the carbon dioxide to sequester the carbon dioxide.
 3882. The method of claim 3877, further comprising using a second portion of the separated carbon dioxide as a flooding agent for enhanced oil recovery.
 3883. The method of claim 3877, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons undergo a reaction within the selected section to increase a H₂ concentration within the produced synthesis gas.
 3884. The method of claim 3877, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within the selected section to increase an energy content of the produced synthesis gas.
 3885. The method of claim 3877, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.
 3886. The method of claim 3877, further comprising generating electricity from the synthesis gas using a fuel cell.
 3887. The method of claim 3877, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent portion of the formation.
 3888. The method of claim 3877, further comprising using a portion of the synthesis gas as a combustion fuel for heating the formation.
 3889. The method of claim 3877, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.
 3890. The method of claim 3877, further comprising converting at least a portion of the produced synthesis gas to methanol.
 3891. The method of claim 3877, further comprising converting at least a portion of the produced synthesis gas to gasoline.
 3892. The method of claim 3877, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.
 3893. The method of claim 3877, wherein a temperature of the one or more heat sources is maintained at a temperature of less than approximately 700° C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of greater than about
 2. 3894. The method of claim 3877, wherein a temperature of the one or more heat sources is maintained at a temperature of greater than approximately 700° C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of less than about
 2. 3895. The method of claim 3877, wherein a temperature of the one or more heat sources is maintained at a temperature of approximately 700° C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of approximately
 2. 3896. The method of claim 3877, wherein a heat source of the one or more of heat sources comprises an electrical heater.
 3897. The method of claim 3877, wherein a heat source of the one or more heat sources comprises a natural distributor heater.
 3898. The method of claim 3877, wherein a heat source of the one or more heat sources comprises a flameless distributed combustor (FDC) heater, and wherein fluids are produced from the wellbore of the FDC heater through a conduit positioned within the wellbore.
 3899. The method of claim 3877, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 3900. The method of claim 3877, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 3901. A method of in situ synthesis gas production, comprising: providing heat from one or more flameless distributed combustor heaters to at least a first portion of a relatively permeable formation containing heavy hydrocarbons; allowing the heat to transfer from the one or more heaters to a selected section of the formation to raise a temperature of the selected section to a temperature sufficient to generate synthesis gas; introducing a synthesis gas producing fluid into the selected section to generate synthesis gas; and removing synthesis gas from the formation.
 3902. The method of claim 3901, wherein the one or more heaters comprise at least two heaters, and wherein superposition of heat from at least the two heaters raises a temperature of the selected section to a temperature sufficient to generate synthesis gas.
 3903. The method of claim 3901, further comprising producing the synthesis gas from the formation under pressure, and generating electricity from the produced synthesis gas by passing the produced synthesis gas through a turbine.
 3904. The method of claim 3901, further comprising producing pyrolyzation products from the formation when raising the temperature of the selected section to the temperature sufficient to generate synthesis gas.
 3905. The method of claim 3901, further comprising separating a portion of carbon dioxide from the removed synthesis gas, and storing the carbon dioxide within a spent portion of the formation.
 3906. The method of claim 3901, further comprising storing carbon dioxide within a spent portion of the formation, wherein an amount of carbon dioxide stored within the spent portion of the formation is equal to or greater than an amount of carbon dioxide within the removed synthesis gas.
 3907. The method of claim 3901, further comprising separating a portion of H₂ from the removed synthesis gas; and using a portion of the separated H₂ as fuel for the one or more heaters.
 3908. The method of claim 3907, further comprising using a portion of exhaust products from one or more heaters as a portion of the synthesis gas producing fluid.
 3909. The method of claim 3901, further comprising using a portion of the removed synthesis gas with a fuel cell to generate electricity.
 3910. The method of claim 3909, wherein the fuel cell produces steam, and wherein a portion of the steam is used as a portion of the synthesis gas producing fluid.
 3911. The method of claim 3909, wherein the fuel cell produces carbon dioxide, and wherein a portion of the carbon dioxide is introduced into the formation to react with carbon within the formation to produce carbon monoxide.
 3912. The method of claim 3909, wherein the fuel cell produces carbon dioxide, and further comprising storing an amount of carbon dioxide within a spent portion of the formation equal or greater to an amount of the carbon dioxide produced by the fuel cell.
 3913. The method of claim 3901, further comprising using a portion of the removed synthesis gas as a feed product for formation of hydrocarbons.
 3914. The method of claim 3901, wherein the synthesis gas producing fluid comprises hydrocarbons having carbon numbers less than 5, and wherein the hydrocarbons crack within the formation to increase an amount of H₂ within the generated synthesis gas.
 3915. The method of claim 3901, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 3916. The method of claim 3901, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 3917. A method of treating a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation with one or more electrical heaters to a temperature sufficient to pyrolyze hydrocarbons within the portion; producing pyrolyzation fluid from the formation; separating a fuel cell feed stream from the pyrolyzation fluid; and directing the fuel cell feed stream to a fuel cell to produce electricity.
 3918. The method of claim 3917, wherein the fuel cell is a molten carbonate fuel cell.
 3919. The method of claim 3917, wherein the fuel cell is a solid oxide fuel cell.
 3920. The method of claim 3917, further comprising using a portion of the produced electricity to power the electrical heaters.
 3921. The method of claim 3917, wherein the fuel cell feed stream comprises H₂ and hydrocarbons having a carbon number of less than
 5. 3922. The method of claim 3917, wherein the fuel cell feed stream comprises H₂ and hydrocarbons having a carbon number of less than
 3. 3923. The method of claim 3917, further comprising hydrogenating the pyrolyzation fluid with a portion of H₂ from the pyrolyzation fluid.
 3924. The method of claim 3917, wherein the hydrogenation is done in situ by directing the 12 into the formation.
 3925. The method of claim 3917, wherein the hydrogenation is done in a surface unit.
 3926. The method of claim 3917, further comprising directing hydrocarbon fluid having carbon numbers less than 5 adjacent to at least one of the electrical heaters, cracking a portion of the hydrocarbons to produce H₂, and producing a portion of the hydrogen from the formation.
 3927. The method of claim 3926, further comprising directing an oxidizing fluid adjacent to at least the one of the electrical heaters, oxidizing coke deposited on or near the at least one of the electrical heaters with the oxidizing fluid.
 3928. The method of claim 3917, further comprising storing CO₂ from the fuel cell within the formation.
 3929. The method of claim 3928, wherein the CO₂ is adsorbed to carbon material within a spent portion of the formation.
 3930. The method of claim 3917, further comprising cooling the portion to form a spent portion of formation.
 3931. The method of claim 3930, wherein cooling the portion comprises introducing water into the portion to produce steam, and removing steam from the formation.
 3932. The method of claim 3931, further comprising using a portion of the removed steam to heat a second portion of the formation.
 3933. The method of claim 3931, further comprising using a portion of the removed steam as a synthesis gas producing fluid in a second portion of the formation.
 3934. The method of claim 3917, further comprising: heating the portion to a temperature sufficient to support generation of synthesis gas after production of the pyrolyzation fluids; introducing a synthesis gas producing fluid into the portion to generate synthesis gas; and removing a portion of the synthesis gas from the formation.
 3935. The method of claim 3934, further comprising producing the synthesis gas from the formation under pressure, and generating electricity from the produced synthesis gas by passing the produced synthesis gas through a turbine.
 3936. The method of claim 3934, further comprising using a first portion of the removed synthesis gas as fuel cell feed.
 3937. The method of claim 3934, further comprising producing steam from operation of the fuel cell, and using the steam as part of the synthesis gas producing fluid.
 3938. The method of claim 3934, further comprising using carbon dioxide from the fuel cell as a part of the synthesis gas producing fluid.
 3939. The method of claim 3934, further comprising using a portion of the synthesis gas to produce hydrocarbon product.
 3940. The method of claim 3934, further comprising cooling the portion to form a spent portion of formation.
 3941. The method of claim 3940, wherein cooling the portion comprises introducing water into the portion to produce steam, and removing steam from the formation.
 3942. The method of claim 3941, further comprising using a portion of the removed steam to heat a second portion of the formation.
 3943. The method of claim 3941, further comprising using a portion of the removed steam as a synthesis gas producing fluid in a second portion of the formation.
 3944. The method of claim 3917, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 3945. The method of claim 3917, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 3946. A method for in situ production of synthesis gas from a relatively permeable formation containing heavy hydrocarbons, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation; producing pyrolysis products from the formation; heating at least a portion of the selected section to a temperature sufficient to generate synthesis gas; providing a synthesis gas generating fluid to at least the portion of the selected section to generate synthesis gas; and producing a portion of the synthesis gas from the formation.
 3947. The method of claim 3946, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 3948. The method of claim 3946, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.
 3949. The method of claim 3946, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400° C. to approximately 1200° C.
 3950. The method of claim 3946, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid; introducing the oxidizing fluid to the zones substantially by diffusion; allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and transferring heat from the zones to the selected section.
 3951. The method of claim 3946, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: introducing an oxidizing fluid into the formation through a wellbore; transporting the oxidizing fluid substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and reacting the oxidizing fluid within the portion of the selected section to generate heat and raise the temperature of the portion.
 3952. The method of claim 3946, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.
 3953. The method of claim 3946, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 3954. The method of claim 3946, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to at least the portion of the selected section comprises introducing steam into the portion.
 3955. The method of claim 3946, further comprising controlling the heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.
 3956. The method of claim 3946, further comprising: monitoring a composition of the produced synthesis gas; and controlling heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain the composition of the produced synthesis gas within a desired range.
 3957. The method of claim 3946, wherein the synthesis gas generating fluid comprises liquid water.
 3958. The method of claim 3946, wherein the synthesis gas generating fluid comprises steam.
 3959. The method of claim 3946, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.
 3960. The method of claim 3959, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 3961. The method of claim 3946, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 3962. The method of claim 3961, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 3963. The method of claim 3946, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.
 3964. The method of claim 3946, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within at least the portion of the selected section to increase a H₂ concentration within the produced synthesis gas.
 3965. The method of claim 3946, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the portion of the selected section to increase an energy content of the produced synthesis gas.
 3966. The method of claim 3946, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.
 3967. The method of claim 3946, further comprising generating electricity from the synthesis gas using a fuel cell.
 3968. The method of claim 3946, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.
 3969. The method of claim 3946, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 3970. The method of claim 3946, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.
 3971. The method of claim 3946, further comprising converting at least a portion of the produced synthesis gas to methanol.
 3972. The method of claim 3946, further comprising converting at least a portion of the produced synthesis gas to gasoline.
 3973. The method of claim 3946, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.
 3974. The method of claim 3946, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 3975. The method of claim 3946, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 3976. A method for in situ production of synthesis gas from a relatively permeable formation containing heavy hydrocarbons, comprising: heating a first portion of the formation to pyrolyze some hydrocarbons within the first portion; allowing the heat to transfer from one or more heat sources to a selected section of the formation, pyrolyzing hydrocarbons within the selected section; producing fluid from the first portion, wherein the fluid comprises an aqueous fluid and a hydrocarbon fluid; heating a second portion of the formation to a temperature sufficient to allow synthesis gas generation; introducing at least a portion of the aqueous fluid to the second section after the section reaches the temperature sufficient to allow synthesis gas generation; and producing synthesis gas from the formation.
 3977. The method of claim 3976, wherein the temperature sufficient to allow synthesis gas generation ranges from approximately 400° C. to approximately 1200° C.
 3978. The method of claim 3976, further comprising separating ammonia within the aqueous phase from the aqueous phase prior to introduction of at least the portion of the aqueous fluid to the second section.
 3979. The method of claim 3976, further comprising heating the second portion of the formation during introduction of at least the portion of the aqueous fluid to the second section to inhibit temperature decrease in the second section due to synthesis gas generation.
 3980. The method of claim 3976, wherein heating the second portion of the formation comprises convecting an oxidizing fluid into a portion of the second portion that is above a temperature sufficient to support oxidation of carbon within the portion with the oxidizing fluid, and reacting the oxidizing fluid with carbon in the portion to generate heat within the portion.
 3981. The method of claim 3976, wherein heating the second portion of the formation comprises diffusing an oxidizing fluid to reaction zones adjacent to wellbores within the formation, oxidizing carbon within the reaction zones to generate heat, and transferring the heat to the second portion.
 3982. The method of claim 3976, wherein heating the second portion of the formation comprises heating the second section by transfer of heat from one or more electrical heaters.
 3983. The method of claim 3976, wherein heating the second portion of the formation comprises heating the second section with a flameless distributed combustor.
 3984. The method of claim 3976, wherein heating the second portion of the formation comprises injecting steam into at least the portion of the formation.
 3985. The method of claim 3976, wherein at least the portion of the aqueous fluid comprises a liquid phase.
 3986. The method of claim 3976, wherein at least a portion of the aqueous fluid comprises a vapor phase.
 3987. The method of claim 3976, further comprising adding carbon dioxide to at least the portion of aqueous fluid to inhibit production of carbon dioxide from carbon within the formation.
 3988. The method of claim 3987, wherein a portion of the carbon dioxide comprises carbon dioxide removed from the formation.
 3989. The method of claim 3976, further comprising adding hydrocarbons with carbon numbers less than 5 to at least the portion of the aqueous fluid to increase a H₂ concentration within the produced synthesis gas.
 3990. The method of claim 3976, further comprising adding hydrocarbons with carbon numbers less than 5 to at least the portion of the aqueous fluid to increase a H₂ concentration within the produced synthesis gas, wherein the hydrocarbons are obtained from the produced fluid.
 3991. The method of claim 3976, further comprising adding hydrocarbons with carbon numbers greater than 4 to at least the portion of the aqueous fluid to increase energy content of the produced synthesis gas.
 3992. The method of claim 3976, further comprising adding hydrocarbons with carbon numbers greater than 4 to at least the portion of the aqueous fluid to increase energy content of the produced synthesis gas, wherein the hydrocarbons are obtained from the produced fluid.
 3993. The method of claim 3976, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.
 3994. The method of claim 3976, further comprising generating electricity from the synthesis gas using a fuel cell.
 3995. The method of claim 3976, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent portion of the formation.
 3996. The method of claim 3976, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 3997. The method of claim 3976, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.
 3998. The method of claim 3976, further comprising converting at least a portion of the produced synthesis gas to methanol.
 3999. The method of claim 3976, further comprising converting at least a portion of the produced synthesis gas to gasoline.
 4000. The method of claim 3976, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.
 4001. The method of claim 3976, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 4002. The method of claim 3976, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 4003. A method for in situ production of synthesis gas from a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation with one or more heat sources to raise a temperature within the portion to a temperature sufficient to allow synthesis gas generation; providing a synthesis gas generating fluid into the portion through at least one injection wellbore to generate synthesis gas from hydrocarbons and the synthesis gas generating fluid; and producing synthesis gas from at least one wellbore in which is positioned a heat source of the one or more heat sources.
 4004. The method of claim 4003, wherein the temperature sufficient to allow synthesis gas generation is within a range from about 400° C. to about 1200° C.
 4005. The method of claim 4003, wherein heating the portion comprises heating the portion to a temperature within a range sufficient to pyrolyze hydrocarbons within the portion, raising the temperature within the portion at a rate of less than about 5° C. per day during pyrolyzation and removing a portion of pyrolyzed fluid from the formation.
 4006. The method of claim 4003, further comprising removing fluid from the formation through at least the one injection wellbore prior to heating the selected section to the temperature sufficient to allow synthesis gas generation.
 4007. The method of claim 4003, wherein the injection wellbore comprises a wellbore of a heat source in which is positioned a heat source of the one or more heat sources.
 4008. The method of claim 4003, further comprising heating the selected portion during providing the synthesis gas generating fluid to inhibit temperature decrease in at least the portion of the selected section due to synthesis gas generation.
 4009. The method of claim 4003, further comprising providing a portion of the heat needed to raise the temperature sufficient to allow synthesis gas generation by convecting an oxidizing fluid to hydrocarbons within the selected section to oxidize a portion of the hydrocarbons and generate heat.
 4010. The method of claim 4003, further comprising controlling the heating of the selected section and provision of the synthesis gas generating fluid to maintain a temperature within the selected section above the temperature sufficient to generate synthesis gas.
 4011. The method of claim 4003, further comprising: monitoring a composition of the produced synthesis gas; and controlling heating of the selected section and provision of the synthesis gas generating fluid to maintain the composition of the produced synthesis gas within a desired range.
 4012. The method of claim 4003, wherein the synthesis gas generating fluid comprises liquid water.
 4013. The method of claim 4003, wherein the synthesis gas generating fluid comprises steam.
 4014. The method of claim 4003, wherein the synthesis gas generating fluid comprises steam to heat the selected section and to generate synthesis gas.
 4015. The method of claim 4003, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.
 4016. The method of claim 4015, wherein a portion of the carbon dioxide comprises carbon dioxide removed from the formation.
 4017. The method of claim 4003, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 4018. The method of claim 4017, wherein a portion of the carbon dioxide comprises carbon dioxide removed from the formation.
 4019. The method of claim 4003, wherein providing the synthesis gas generating fluid to the selected section comprises raising a water table of the formation to allow water to enter the selected section.
 4020. The method of claim 4003, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons undergo a reaction within the selected section to increase a concentration within the produced synthesis gas.
 4021. The method of claim 4003, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within the selected section to increase an energy content of the produced synthesis gas.
 4022. The method of claim 4003, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.
 4023. The method of claim 4003, further comprising generating electricity from the synthesis gas using a fuel cell.
 4024. The method of claim 4003, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent portion of the formation.
 4025. The method of claim 4003, further comprising using a portion of the synthesis gas as a combustion fuel for heating the formation.
 4026. The method of claim 4003, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.
 4027. The method of claim 4003, further comprising converting at least a portion of the produced synthesis gas to methanol.
 4028. The method of claim 4003, further comprising converting at least a portion of the produced synthesis gas to gasoline.
 4029. The method of claim 4003, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.
 4030. The method of claim 4003, wherein a temperature of at least the one heat source wellbore is maintained at a temperature of less than approximately 700° C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of greater than about
 2. 4031. The method of claim 4003, wherein a temperature of at least the one heat source wellbore is maintained at a temperature of greater than approximately 700° C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of less than about
 2. 4032. The method of claim 4003, wherein a temperature of at least the one heat source wellbore is maintained at a temperature of approximately 700° C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of approximately
 2. 4033. The method of claim 4003, wherein a heat source of the one or more heat sources comprises an electrical heater.
 4034. The method of claim 4003, wherein a heat source of the one or more heat sources comprises a natural distributor heater.
 4035. The method of claim 4003, wherein a heat source of the one or more heat sources comprises a flameless distributed combustor (FDC) heater, and wherein fluids are produced from the wellbore of the FDC heater through a conduit positioned within the wellbore.
 4036. The method of claim 4003, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 4037. The method of claim 4003, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 4038. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least a portion of the hydrocarbon containing material within the selected section of the formation; producing pyrolysis products from the formation; heating a first portion of a formation with one or more heat sources to a temperature sufficient to allow generation of synthesis gas; providing a first synthesis gas generating fluid to the first portion to generate a first synthesis gas; removing a portion of the first synthesis gas from the formation; heating a second portion of a formation with one or more heat sources to a temperature sufficient to allow generation of synthesis gas having a H₂ to CO ratio greater than a H₂ to CO ratio of the first synthesis gas; providing a second synthesis gas generating component to the second portion to generate a second synthesis gas; removing a portion of the second synthesis gas from the formation; and blending a portion of the first synthesis gas with a portion of the second synthesis gas to produce a blended synthesis gas having a selected H₂ to CO ratio.
 4039. The method of claim 4038, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 4040. The method of claim 4038, wherein the first synthesis gas generating fluid and second synthesis gas generating fluid comprise the same component.
 4041. The method of claim 4038, further comprising controlling the temperature in the first portion to control a composition of the first synthesis gas.
 4042. The method of claim 4038, further comprising controlling the temperature in the second portion to control a composition of the second synthesis gas.
 4043. The method of claim 4038, wherein the selected ratio is controlled to be approximately 2:1H₂ to CO.
 4044. The method of claim 4038, wherein the selected ratio is controlled to range from approximately 1.8:1 to approximately 2.2:1H₂ to CO.
 4045. The method of claim 4038, wherein the selected ratio is controlled to be approximately 3:1H₂ to CO.
 4046. The method of claim 4038, wherein the selected ratio is controlled to range from approximately 2.8:1 to approximately 3.2:1H₂ to CO.
 4047. The method of claim 4038, further comprising providing at least a portion of the produced blended synthesis gas to a condensable hydrocarbon synthesis process to produce condensable hydrocarbons.
 4048. The method of claim 4047, wherein the condensable hydrocarbon synthesis process comprises a Fischer-Tropsch process.
 4049. The method of claim 4048, further comprising cracking at least a portion of the condensable hydrocarbons to form middle distillates.
 4050. The method of claim 4038, further comprising providing at least a portion of the produced blended synthesis gas to a catalytic methanation process to produce methane.
 4051. The method of claim 4038, further comprising providing at least a portion of the produced blended synthesis gas to a methanol-synthesis process to produce methanol.
 4052. The method of claim 4038, further comprising providing at least a portion of the produced blended synthesis gas to a gasoline-synthesis process to produce gasoline.
 4053. The method of claim 4038, wherein removing a portion of the second synthesis gas comprises withdrawing second synthesis gas through a production well, wherein a temperature of the production well adjacent to a second syntheses gas production zone is maintained at a substantially constant temperature configured to produce second synthesis gas having the H₂ to CO ratio greater the first synthesis gas.
 4054. The method of claim 4038, wherein the first synthesis gas producing fluid comprises CO₂ and wherein the temperature of the first portion is at a temperature that will result in conversion of CO₂ and carbon from the first portion to CO to generate a CO rich first synthesis gas.
 4055. The method of claim 4038, wherein the second synthesis gas producing fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons react within the formation to increase a H₂ concentration within the produced second synthesis gas.
 4056. The method of claim 4038, wherein blending a portion of the first synthesis gas with a portion of the second synthesis gas comprises producing an intermediate mixture having a H₂ to CO mixture of less than the selected ratio, and subjecting the intermediate mixture to a shift reaction to reduce an amount of CO and increase an amount of H₂ to produce the selected ratio of H₂ to CO.
 4057. The method of claim 4038, further comprising removing an excess of first synthesis gas from the first portion to have an excess of CO, subjecting the first synthesis gas to a shift reaction to reduce an amount of CO and increase an amount of H₂ before blending the first synthesis gas with the second synthesis gas.
 4058. The method of claim 4038, further comprising removing the first synthesis gas from the formation under pressure, and passing removed first synthesis gas through a turbine to generate electricity.
 4059. The method of claim 4038, further comprising removing the second synthesis gas from the formation under pressure, and passing removed second synthesis gas through a turbine to generate electricity.
 4060. The method of claim 4038, further comprising generating electricity from the blended synthesis gas using a fuel cell.
 4061. The method of claim 4038, further comprising generating electricity from the blended synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent portion of the formation.
 4062. The method of claim 4038, further comprising using at least a portion of the blended synthesis gas as a combustion fuel for heating the formation.
 4063. The method of claim 4038, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.
 4064. The method of claim 4038, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400° C. to approximately 1200° C.
 4065. The method of claim 4038, wherein heating the first a portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid; introducing the oxidizing fluid to the zones substantially by diffusion; allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and transferring heat from the zones to the selected section.
 4066. The method of claim 4038, wherein heating the second portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid; introducing the oxidizing fluid to the zones substantially by diffusion; allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and transferring heat from the zones to the selected section.
 4067. The method of claim 4038, wherein heating the first portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: introducing an oxidizing fluid into the formation through a wellbore; transporting the oxidizing fluid substantially by convection into the first portion of the selected section, wherein the first portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and reacting the oxidizing fluid within the first portion of the selected section to generate heat and raise the temperature of the first portion.
 4068. The method of claim 4038, wherein heating the second portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: introducing an oxidizing fluid into the formation through a wellbore; transporting the oxidizing fluid substantially by convection into the second portion of the selected section, wherein the second portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and reacting the oxidizing fluid within the second portion of the selected section to generate heat and raise the temperature of the second portion.
 4069. The method of claim 4038, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.
 4070. The method of claim 4038, wherein the one or more heat sources comprises one or more natural distributed combustors.
 4071. The method of claim 4038, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 4072. The method of claim 4038, wherein heating the first portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a first synthesis gas generating fluid to the first portion of the selected section comprises introducing steam into the first portion.
 4073. The method of claim 4038, wherein heating the second portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a second synthesis gas generating fluid to the second portion of the selected section comprises introducing steam into the second portion.
 4074. The method of claim 4038, further comprising controlling the heating of the first portion of selected section and provision of the first synthesis gas generating fluid to maintain a temperature within the first portion of the selected section above the temperature sufficient to generate synthesis gas.
 4075. The method of claim 4038, further comprising controlling the heating of the second portion of selected section and provision of the second synthesis gas generating fluid to maintain a temperature within the second portion of the selected section above the temperature sufficient to generate synthesis gas.
 4076. The method of claim 4038, wherein the first synthesis gas generating fluid comprises liquid water.
 4077. The method of claim 4038, wherein the second synthesis gas generating fluid comprises liquid water.
 4078. The method of claim 4038, wherein the first synthesis gas generating fluid comprises steam.
 4079. The method of claim 4038, wherein the second synthesis gas generating fluid comprises steam.
 4080. The method of claim 4038, wherein the first synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.
 4081. The method of claim 4080, wherein a portion of the carbon dioxide within the first synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4082. The method of claim 4038, wherein the second synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.
 4083. The method of claim 4082, wherein a portion of the carbon dioxide within the second synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4084. The method of claim 4038, wherein the first synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 4085. The method of claim 4084, wherein a portion of the carbon dioxide within the first synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4086. The method of claim 4038, wherein the second synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 4087. The method of claim 4086, wherein a portion of the carbon dioxide within the second synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4088. The method of claim 4038, wherein providing the first synthesis gas generating fluid to the first portion of the selected section comprises raising a water table of the formation to allow water to flow into the first portion of the selected section.
 4089. The method of claim 4038, wherein providing the second synthesis gas generating fluid to the second portion of the selected section comprises raising a water table of the formation to allow water to flow into the second portion of the selected section.
 4090. The method of claim 4038, wherein the first synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within the first portion of the selected section to increase a H₂ concentration within the produced first synthesis gas.
 4091. The method of claim 4038, wherein the second synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within the second portion of the selected section to increase a H₂ concentration within the produced second synthesis gas.
 4092. The method of claim 4038, wherein the first synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within the first portion of the selected section to increase an energy content of the produced first synthesis gas.
 4093. The method of claim 4038, wherein the second synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the second portion of the selected section to increase an energy content of the second produced synthesis gas.
 4094. The method of claim 4038, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced blended synthesis gas through a turbine to generate electricity.
 4095. The method of claim 4038, further comprising generating electricity from the blended synthesis gas using a fuel cell.
 4096. The method of claim 4038, further comprising generating electricity from the blended synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.
 4097. The method of claim 4038, further comprising using a portion of the blended synthesis gas as a combustion fuel for the one or more heat sources.
 4098. The method of claim 4038, further comprising using a portion of the first synthesis gas as a combustion fuel for the one or more heat sources.
 4099. The method of claim 4038, further comprising using a portion of the second synthesis gas as a combustion fuel for the one or more heat sources.
 4100. The method of claim 4038, further comprising using a portion of the blended synthesis gas as a combustion fuel for the one or more heat sources.
 4101. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation; producing pyrolysis products from the formation; heating at least a portion of the selected section to a temperature sufficient to generate synthesis gas; controlling a temperature of at least a portion of the selected section to generate synthesis gas having a selected 12 to CO ratio; providing a synthesis gas generating fluid to at least the portion of the selected section to generate synthesis gas; and producing a portion of the synthesis gas from the formation.
 4102. The method of claim 4101, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 4103. The method of claim 4101, wherein the selected ratio is controlled to be approximately 2:1H₂ to CO.
 4104. The method of claim 4101, wherein the selected ratio is controlled to range from approximately 1.8:1 to approximately 2.2:1H₂ to CO.
 4105. The method of claim 4101, wherein the selected ratio is controlled to be approximately 3:1H₂ to CO.
 4106. The method of claim 4101, wherein the selected ratio is controlled to range from approximately 2.8:1 to approximately 3.2:1H₂ to CO.
 4107. The method of claim 4101, further comprising providing at least a portion of the produced synthesis gas to a condensable hydrocarbon synthesis process to produce condensable hydrocarbons.
 4108. The method of claim 4107, wherein the condensable hydrocarbon synthesis process comprises a Fischer-Tropsch process.
 4109. The method of claim 4108, further comprising cracking at least a portion of the condensable hydrocarbons to form middle distillates.
 4110. The method of claim 4101, further comprising providing at least a portion of the produced synthesis gas to a catalytic methanation process to produce methane.
 4111. The method of claim 4101, further comprising providing at least a portion of the produced synthesis gas to a methanol-synthesis process to produce methanol.
 4112. The method of claim 4101, further comprising providing at least a portion of the produced synthesis gas to a gasoline-synthesis process to produce gasoline.
 4113. The method of claim 4101, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.
 4114. The method of claim 4101, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400° C. to approximately 1200° C.
 4115. The method of claim 4101, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid; introducing the oxidizing fluid to the zones substantially by diffusion; allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and transferring heat from the zones to the selected section.
 4116. The method of claim 4101, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: introducing an oxidizing fluid into the formation through a wellbore; transporting the oxidizing fluid substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and reacting the oxidizing fluid within the portion of the selected section to generate heat and raise the temperature of the portion.
 4117. The method of claim 4101, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.
 4118. The method of claim 4101, wherein the one or more heat sources comprises one or more natural distributed combustors.
 4119. The method of claim 4101, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 4120. The method of claim 4101, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to at least the portion of the selected section comprises introducing steam into the portion.
 4121. The method of claim 4101, further comprising controlling the heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.
 4122. The method of claim 4101, wherein the synthesis gas generating fluid comprises liquid water.
 4123. The method of claim 4101, wherein the synthesis gas generating fluid comprises steam.
 4124. The method of claim 4101, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.
 4125. The method of claim 4124, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4126. The method of claim 4101, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 4127. The method of claim 4126, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4128. The method of claim 4101, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.
 4129. The method of claim 4101, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within at least the portion of the selected section to increase a H₂ concentration within the produced synthesis gas.
 4130. The method of claim 4101, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the portion of the selected section to increase an energy content of the produced synthesis gas.
 4131. The method of claim 4101, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.
 4132. The method of claim 4101, further comprising generating electricity from the synthesis gas using a fuel cell.
 4133. The method of claim 4101, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.
 4134. The method of claim 4101, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 4135. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation; producing pyrolysis products from the formation; heating at least a portion of the selected section to a temperature sufficient to generate synthesis gas; controlling a temperature in or proximate to a synthesis gas production well to generate synthesis gas having a selected H₂ to CO ratio; providing a synthesis gas generating fluid to at least the portion of the selected section to generate synthesis gas; and producing synthesis gas from the formation.
 4136. The method of claim 4135, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 4137. The method of claim 4135, wherein the selected ratio is controlled to be approximately 2:1H₂ to CO.
 4138. The method of claim 4135, wherein the selected ratio is controlled to range from approximately 1.8:1 to approximately 2.2:1H₂ to CO.
 4139. The method of claim 4135, wherein the selected ratio is controlled to be approximately 3:1H₂ to CO.
 4140. The method of claim 4135, wherein the selected ratio is controlled to range from approximately 2.8:1 to approximately 3.2:1H₂ to CO.
 4141. The method of claim 4135, further comprising providing at least a portion of the produced synthesis gas to a condensable hydrocarbon synthesis process to produce condensable hydrocarbons.
 4142. The method of claim 4141, wherein the condensable hydrocarbon synthesis process comprises a Fischer-Tropsch process.
 4143. The method of claim 4142, further comprising cracking at least a portion of the condensable hydrocarbons to form middle distillates.
 4144. The method of claim 4135, further comprising providing at least a portion of the produced synthesis gas to a catalytic methanation process to produce methane.
 4145. The method of claim 4135, further comprising providing at least a portion of the produced synthesis gas to a methanol-synthesis process to produce methanol.
 4146. The method of claim 4135, further comprising providing at least a portion of the produced synthesis gas to a gasoline-synthesis process to produce gasoline.
 4147. The method of claim 4135, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.
 4148. The method of claim 4135, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400° C. to approximately 1200° C.
 4149. The method of claim 4135, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid; introducing the oxidizing fluid to the zones substantially by diffusion; allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and transferring heat from the zones to the selected section.
 4150. The method of claim 4135, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: introducing an oxidizing fluid into the formation through a wellbore; transporting the oxidizing fluid substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and reacting the oxidizing fluid within the portion of the selected section to generate heat and raise the temperature of the portion.
 4151. The method of claim 4135, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.
 4152. The method of claim 4135, wherein the one or more heat sources comprises one or more natural distributed combustors.
 4153. The method of claim 4135, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 4154. The method of claim 4135, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to at least the portion of the selected section comprises introducing steam into the portion.
 4155. The method of claim 4135, further comprising controlling the heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.
 4156. The method of claim 4135, wherein the synthesis gas generating fluid comprises liquid water.
 4157. The method of claim 4135, wherein the synthesis gas generating fluid comprises steam.
 4158. The method of claim 4135, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.
 4159. The method of claim 4158, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4160. The method of claim 4135, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 4161. The method of claim 4160, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4162. The method of claim 4135, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.
 4163. The method of claim 4135, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within at least the portion of the selected section to increase a H₂ concentration within the produced synthesis gas.
 4164. The method of claim 4135, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the portion of the selected section to increase an energy content of the produced synthesis gas.
 4165. The method of claim 4135, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.
 4166. The method of claim 4135, further comprising generating electricity from the synthesis gas using a fuel cell.
 4167. The method of claim 4135, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.
 4168. The method of claim 4135, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 4169. A method of treating a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation; producing pyrolysis products from the formation; heating at least a portion of the selected section to a temperature sufficient to generate synthesis gas; controlling a temperature of at least a portion of the selected section to generate synthesis gas having a H₂ to CO ratio different than a selected H₂ to CO ratio; providing a synthesis gas generating fluid to at least the portion of the selected section to generate synthesis gas; and producing synthesis gas from the formation; providing at least a portion of the produced synthesis gas to a shift process wherein an amount of carbon monoxide is converted to carbon dioxide; separating at least a portion of the carbon dioxide to obtain a gas having a selected H₂ to CO ratio.
 4170. The method of claim 4169, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 4171. The method of claim 4169, wherein the selected ratio is controlled to be approximately 2:1H₂ to CO.
 4172. The method of claim 4169, wherein the selected ratio is controlled to range from approximately 1.8:1 to 2.2:1H₂ to CO.
 4173. The method of claim 4169, wherein the selected ratio is controlled to be approximately 3:1H₂ to CO.
 4174. The method of claim 4169, wherein the selected ratio is controlled to range from approximately 2.8:1 to 3.2:1H₂ to CO.
 4175. The method of claim 4169, further comprising providing at least a portion of the produced synthesis gas to a condensable hydrocarbon synthesis process to produce condensable hydrocarbons.
 4176. The method of claim 4175, wherein the condensable hydrocarbon synthesis process comprises a Fischer-Tropsch process.
 4177. The method of claim 4176, further comprising cracking at least a portion of the condensable hydrocarbons to form middle distillates.
 4178. The method of claim 4169, further comprising providing at least a portion of the produced synthesis gas to a catalytic methanation process to produce methane.
 4179. The method of claim 4169, further comprising providing at least a portion of the produced synthesis gas to a methanol-synthesis process to produce methanol.
 4180. The method of claim 4169, further comprising providing at least a portion of the produced synthesis gas to a gasoline-synthesis process to produce gasoline.
 4181. The method of claim 4169, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.
 4182. The method of claim 4169, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400° C. to approximately 1200° C.
 4183. The method of claim 4169, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid; introducing the oxidizing fluid to the zones substantially by diffusion; allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and transferring heat from the zones to the selected section.
 4184. The method of claim 4169, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises: introducing an oxidizing fluid into the formation through a wellbore; transporting the oxidizing fluid substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and reacting the oxidizing fluid within the portion of the selected section to generate heat and raise the temperature of the portion.
 4185. The method of claim 4169, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.
 4186. The method of claim 4169, wherein the one or more heat sources comprises one or more natural distributed combustors.
 4187. The method of claim 4169, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 4188. The method of claim 4169, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to at least the portion of the selected section comprises introducing steam into the portion.
 4189. The method of claim 4169, further comprising controlling the heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.
 4190. The method of claim 4169, wherein the synthesis gas generating fluid comprises liquid water.
 4191. The method of claim 4169, wherein the synthesis gas generating fluid comprises steam.
 4192. The method of claim 4169, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.
 4193. The method of claim 4192, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4194. The method of claim 4169, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 4195. The method of claim 4194, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4196. The method of claim 4169, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.
 4197. The method of claim 4169, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within at least the portion of the selected section to increase a H₂ concentration within the produced synthesis gas.
 4198. The method of claim 4169, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the portion of the selected section to increase an energy content of the produced synthesis gas.
 4199. The method of claim 4169, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.
 4200. The method of claim 4169, further comprising generating electricity from the synthesis gas using a fuel cell.
 4201. The method of claim 4169, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.
 4202. The method of claim 4169, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 4203. A method of forming a spent portion of formation within a relatively permeable formation containing heavy hydrocarbons, comprising: heating a first portion of the formation to pyrolyze hydrocarbons within the first portion; and cooling the first portion.
 4204. The method of claim 4203, wherein heating the first portion comprises transferring heat to the first portion from one or more electrical heaters.
 4205. The method of claim 4203, wherein heating the first portion comprises transferring heat to the first portion from one or more natural distributed combustors.
 4206. The method of claim 4203, wherein heating the first portion comprises transferring heat to the first portion from one or more flameless distributed combustors.
 4207. The method of claim 4203, wherein heating the first portion comprises transferring heat to the first portion from heat transfer fluid flowing within one or more wellbores within the formation.
 4208. The method of claim 4207, wherein the heat transfer fluid comprises steam.
 4209. The method of claim 4207, wherein the heat transfer fluid comprises combustion products from a burner.
 4210. The method of claim 4203, wherein heating the first portion comprises transferring heat to the first portion from at least two heater wells positioned within the formation, wherein the at least two heater wells are placed in a substantially regular pattern, wherein the substantially regular pattern comprises repetition of a base heater unit, and wherein the base heater unit is formed of a number of heater wells.
 4211. The method of claim 4210, wherein a spacing between a pair of adjacent heater wells is within a range from about 6 m to about 15 m.
 4212. The method of claim 4210, further comprising removing fluid from the formation through one or more production wells.
 4213. The method of claim 4212, wherein the one or more production wells are located in a pattern, and wherein the one or more production wells are positioned substantially at centers of base heater units.
 4214. The method of claim 4210, wherein the heater unit comprises three heater wells positioned substantially at apexes of an equilateral triangle.
 4215. The method of claim 4210, wherein the heater unit comprises four heater wells positioned substantially at apexes of a rectangle.
 4216. The method of claim 4210, wherein the heater unit comprises five heater wells positioned substantially at apexes of a regular pentagon.
 4217. The method of claim 4210, wherein the heater unit comprises six heater wells positioned substantially at apexes of a regular hexagon.
 4218. The method of claim 4203, further comprising introducing water to the first portion to cool the formation.
 4219. The method of claim 4203, further comprising removing steam from the formation.
 4220. The method of claim 4219, further comprising using a portion of the removed steam to heat a second portion of the formation.
 4221. The method of claim 4203, further comprising removing pyrolyzation products from the formation.
 4222. The method of claim 4203, further comprising generating synthesis gas within the portion by introducing a synthesis gas generating fluid into the portion, and removing synthesis gas from the formation.
 4223. The method of claim 4203, further comprising heating a second section of the formation to pyrolyze hydrocarbons within the second portion, removing pyrolyzation fluid from the second portion, and storing a portion of the removed pyrolyzation fluid within the first portion.
 4224. The method of claim 4223, wherein the portion of the removed pyrolyzation fluid is stored within the first portion when surface facilities that process the removed pyrolyzation fluid are not able to process the portion of the removed pyrolyzation fluid.
 4225. The method of claim 4223, further comprising heating the first portion to facilitate removal of the stored pyrolyzation fluid from the first portion.
 4226. The method of claim 4203, further comprising generating synthesis gas within a second portion of the formation, removing synthesis gas from the second portion, and storing a portion of the removed synthesis gas within the first portion.
 4227. The method of claim 4226, wherein the portion of the removed synthesis gas from the second portion is stored within the first portion when surface facilities that process the removed synthesis gas are not able to process the portion of the removed synthesis gas.
 4228. The method of claim 4226, further comprising heating the first portion to facilitate removal of the stored synthesis gas from the first portion.
 4229. The method of claim 4203, further comprising removing at least a portion of hydrocarbon containing material in the first portion and, further comprising using at least a portion of the hydrocarbon containing material removed from the formation in a metallurgical application.
 4230. The method of claim 4229, wherein the metallurgical application comprises steel manufacturing.
 4231. A method of sequestering carbon dioxide within a relatively permeable formation containing heavy hydrocarbons, comprising: heating a portion of the formation; allowing the portion to cool; and storing carbon dioxide within the portion.
 4232. The method of claim 4231, further comprising raising a water level within the portion to inhibit migration of the carbon dioxide from the portion.
 4233. The method of claim 4231, further comprising heating the portion to release carbon dioxide, and removing carbon dioxide from the portion.
 4234. The method of claim 4231, further comprising pyrolyzing hydrocarbons within the portion during heating of the portion, and removing pyrolyzation product from the formation.
 4235. The method of claim 4231, further comprising producing synthesis gas from the portion during the heating of the portion, and removing synthesis gas from the formation.
 4236. The method of claim 4231, wherein heating the portion comprises: heating hydrocarbon containing material adjacent to one or more wellbores to a temperature sufficient to support oxidation of the hydrocarbon containing material with an oxidizing fluid; introducing the oxidizing fluid to hydrocarbon containing material adjacent to the one or more wellbores to oxidize the hydrocarbons and produce heat; and conveying produced heat to the portion.
 4237. The method of claim 4236, wherein heating hydrocarbon containing material adjacent to the one or more wellbores comprises electrically heating the hydrocarbon containing material.
 4238. The method of claim 4236, wherein the temperature sufficient to support oxidation is in a range from approximately 200° C. to approximately 1200° C.
 4239. The method of claim 4231, wherein heating the portion comprises circulating heat transfer fluid through one or more heating wells within the formation.
 4240. The method of claim 4239, wherein the heat transfer fluid comprises combustion products from a burner.
 4241. The method of claim 4239, wherein the heat transfer fluid comprises steam.
 4242. The method of claim 4231, further comprising removing fluid from the formation during heating of the formation, and combusting a portion of the removed fluid to generate heat to heat the formation.
 4243. The method of claim 4231, further comprising using at least a portion of the carbon dioxide for hydrocarbon bed demethanation prior to storing the carbon dioxide within the portion.
 4244. The method of claim 4231, further comprising using a portion of the carbon dioxide for enhanced oil recovery prior to storing the carbon dioxide within the portion.
 4245. The method of claim 4231, wherein at least a portion of the carbon dioxide comprises carbon dioxide generated in a fuel cell.
 4246. The method of claim 4231, wherein at least a portion of the carbon dioxide comprises carbon dioxide formed as a combustion product.
 4247. The method of claim 4231, further comprising allowing the portion to cool by introducing water to the portion; and removing the water from the formation as steam.
 4248. The method of claim 4247, further comprising using the steam as a heat transfer fluid to heat a second portion of the formation.
 4249. The method of claim 4231, wherein storing carbon dioxide in the portion comprises adsorbing carbon dioxide to hydrocarbon containing material within the formation.
 4250. The method of claim 4231, wherein storing carbon dioxide comprises passing a first fluid stream comprising the carbon dioxide and other fluid through the portion; adsorbing carbon dioxide onto hydrocarbon containing material within the formation; and removing a second fluid stream from the formation, wherein a concentration of the other fluid in the second fluid stream is greater than concentration of other fluid in the first stream due to the absence of the adsorbed carbon dioxide in the second stream.
 4251. The method of claim 4231, wherein an amount of carbon dioxide stored within the portion is equal to or greater than an amount of carbon dioxide generated within the portion and removed from the formation during heating of the portion.
 4252. The method of claim 4231, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 4253. The method of claim 4231, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 4254. A method of in situ sequestration of carbon dioxide within a relatively permeable formation containing heavy hydrocarbons in situ, comprising: providing heat from one or more heat sources to at least a first portion of the formation; allowing the heat to transfer from one or more sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation; producing pyrolyzation fluids, wherein the pyrolyzation fluids comprise carbon dioxide; and storing an amount of carbon dioxide in the formation, wherein the amount of stored carbon dioxide is equal to or greater than an amount of carbon dioxide within the pyrolyzation fluids.
 4255. The method of claim 4254, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 4256. The method of claim 4254, wherein the carbon dioxide is stored within a spent portion of the formation.
 4257. The method of claim 4254, wherein a portion of the carbon dioxide stored within the formation is carbon dioxide separated from the pyrolyzation fluids.
 4258. The method of claim 4254, further comprising separating a portion of carbon dioxide from the pyrolyzation fluids, and using the carbon dioxide as a flooding agent in enhanced oil recovery.
 4259. The method of claim 4254, further comprising separating a portion of carbon dioxide from the pyrolyzation fluids, and using the carbon dioxide as a synthesis gas generating fluid for the generation of synthesis gas from a section of the formation that is heated to a temperature sufficient to generate synthesis gas upon introduction of the synthesis gas generating fluid.
 4260. The method of claim 4254, further comprising separating a portion of carbon dioxide from the pyrolyzation fluids, and using the carbon dioxide to displace hydrocarbon bed methane.
 4261. The method of claim 4260, wherein the hydrocarbon bed is a deep hydrocarbon bed located over 760 m below ground surface.
 4262. The method of claim 4260, further comprising adsorbing a portion of the carbon dioxide within the hydrocarbon bed.
 4263. The method of claim 4254, further comprising using at least a portion of the pyrolyzation fluids as a feed stream for a fuel cell.
 4264. The method of claim 4263, wherein the fuel cell generates carbon dioxide, and further comprising storing an amount of carbon dioxide equal to or greater than an amount of carbon dioxide generated by the fuel cell within the formation.
 4265. The method of claim 4254, wherein a spent portion of the formation comprises hydrocarbon containing material within a section of the formation that has been heated and from which condensable hydrocarbons have been produced, and wherein the spent portion of the formation is at a temperature at which carbon dioxide adsorbs onto the hydrocarbon containing material.
 4266. The method of claim 4254, further comprising raising a water level within the spent portion to inhibit migration of the carbon dioxide from the portion.
 4267. The method of claim 4254, wherein producing fluids from the formation comprises removing pyrolyzation products from the formation.
 4268. The method of claim 4254, wherein producing fluids from the formation comprises heating the selected section to a temperature sufficient to generate synthesis gas; introducing a synthesis gas generating fluid into the selected section; and removing synthesis gas from the formation.
 4269. The method of claim 4268, wherein the temperature sufficient to generate synthesis gas ranges from about 400° C. to about 1200° C.
 4270. The method of claim 4268, wherein heating the selected section comprises introducing an oxidizing fluid into the selected section, reacting the oxidizing fluid within the selected section to heat the selected section.
 4271. The method of claim 4268, wherein heating the selected section comprises: heating hydrocarbon containing material adjacent to one or more wellbores to a temperature sufficient to support oxidation of the hydrocarbon containing material with an oxidant; introducing the oxidant to hydrocarbon containing material adjacent to the one or more wellbores to oxidize the hydrocarbons and produce heat; and conveying produced heat to the portion.
 4272. The method of claim 4254, wherein the one or more heat sources comprise electrical heaters.
 4273. The method of claim 4254, wherein the one or more heat sources comprise flameless distributed combustors.
 4274. The method of claim 4273, wherein a portion of fuel for the one or more flameless distributed combustors is obtained from the formation.
 4275. The method of claim 4254, wherein the one or more heat sources comprise heater wells in the formation through which heat transfer fluid is circulated.
 4276. The method of claim 4275, wherein the heat transfer fluid comprises combustion products.
 4277. The method of claim 4275, wherein the heat transfer fluid comprises steam.
 4278. The method of claim 4254, wherein condensable hydrocarbons are produced under pressure, and further comprising generating electricity by passing a portion of the produced fluids through a turbine.
 4279. The method of claim 4254, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.
 4280. The method of claim 4254, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.
 4281. A method for in situ production of energy from a relatively permeable formation containing heavy hydrocarbons, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least a portion of the hydrocarbons within the selected section of the formation; producing pyrolysis products from the formation; providing at least a portion of the pyrolysis products to a reformer to generate synthesis gas; producing the synthesis gas from the reformer; providing at least a portion of the produced synthesis gas to a fuel cell to produce electricity, wherein the fuel cell produces a carbon dioxide containing exit stream; and storing at least a portion of the carbon dioxide in the carbon dioxide containing exit stream in a subsurface formation.
 4282. The method of claim 4281, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 4283. The method of claim 4281, wherein at least a portion of the pyrolysis products are used as fuel in the reformer.
 4284. The method of claim 4281, wherein the synthesis gas comprises substantially of H₂.
 4285. The method of claim 4281, wherein the subsurface formation is a spent portion of the formation.
 4286. The method of claim 4281, wherein the subsurface formation is an oil reservoir.
 4287. The method of claim 4286, wherein at least a portion of the carbon dioxide is used as a drive fluid for enhanced oil recovery in the oil reservoir.
 4288. The method of claim 4281, wherein the subsurface formation is a coal formation.
 4289. The method of claim 4288, wherein at least a portion of the carbon dioxide is used to produce methane from the coal formation.
 4290. The method of claim 4288, wherein the coal formation is located over about 760 m below ground surface.
 4291. The method of claim 4289, further comprising sequestering at least a portion of the carbon dioxide within the coal formation.
 4292. The method of claim 4281, wherein the reformer produces a reformer carbon dioxide containing exit stream.
 4293. The method of claim 4291, further comprising storing at least a portion of the carbon dioxide in the reformer carbon dioxide containing exit stream in the subsurface formation.
 4294. The method of claim 4293, wherein the subsurface formation is a spent portion of the formation.
 4295. The method of claim 4293, wherein the subsurface formation is an oil reservoir.
 4296. The method of claim 4295, wherein at least a portion of the carbon dioxide in the reformer carbon dioxide containing exit stream is used as a drive fluid for enhanced oil recovery in the oil reservoir.
 4297. The method of claim 4293, wherein the subsurface formation is a coal formation.
 4298. The method of claim 4297, wherein at least a portion of the carbon dioxide in the reformer carbon dioxide containing exit stream is used to produce methane from the coal formation.
 4299. The method of claim 4297, wherein the coal formation is located over about 760 m below ground surface.
 4300. The method of claim 4298, further comprising sequestering at least a portion of the carbon dioxide in the reformer carbon dioxide containing exit stream within the coal formation.
 4301. The method of claim 4281, wherein the fuel cell is a molten carbonate fuel cell.
 4302. The method of claim 4281, wherein the fuel cell is a solid oxide fuel cell.
 4303. The method of claim 4281, further comprising using a portion of the produced electricity to power electrical heaters within the formation.
 4304. The method of claim 4281, further comprising using a portion of the produced pyrolysis products as a feed stream for the fuel cell.
 4305. The method of claim 4281, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.
 4306. The method of claim 4281, wherein the one or more heat sources comprise one or more flameless distributed combustors disposed in the formation.
 4307. The method of claim 4306, wherein a portion of fuel for the flameless distributed combustors is obtained from the formation.
 4308. The method of claim 4281, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 4309. The method of claim 4281, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 4310. A method for producing ammonia using a relatively permeable formation containing heavy hydrocarbons, comprising: separating air to produce an O₂ rich stream and a N₂ rich stream; heating a selected section of the formation to a temperature sufficient to support reaction of hydrocarbon containing material in the formation to form synthesis gas; providing synthesis gas generating fluid and at least a portion of the O₂ rich stream to the selected section; allowing the synthesis gas generating fluid and O₂ in the O₂ rich stream to react with at least a portion of the hydrocarbon containing material in the formation to generate synthesis gas; producing synthesis gas from the formation, wherein the synthesis gas comprises H₂ and CO; providing at least a portion of the H₂ in the synthesis gas to an ammonia synthesis process; providing N₂ to the ammonia synthesis process; and using the ammonia synthesis process to generate ammonia.
 4311. The method of claim 4310, wherein the ratio of the H₂ to N₂ provided to the ammonia synthesis process is approximately 3:1.
 4312. The method of claim 4310, wherein the ratio of the H₂ to N₂ provided to the ammonia synthesis process ranges from approximately 2.8:1 to approximately 3.2:1.
 4313. The method of claim 4310, wherein the temperature sufficient to support reaction of hydrocarbon containing material in the formation to form synthesis gas ranges from approximately 400° C. to approximately 1200° C.
 4314. The method of claim 4310, further comprising separating at least a portion of carbon dioxide in the synthesis gas from at least a portion of the synthesis gas.
 4315. The method of claim 4314, wherein the carbon dioxide is separated from the synthesis gas by an amine separator.
 4316. The method of claim 4315, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process to produce urea.
 4317. The method of claim 4310, wherein at least a portion of the N₂ stream is used to condense hydrocarbons with 4 or more carbon atoms from a pyrolyzation fluid.
 4318. The method of claim 4310, wherein at least a portion of the N₂ rich stream is provided to the ammonia synthesis process.
 4319. The method of claim 4310, wherein the air is separated by cryogenic distillation.
 4320. The method of claim 4310, wherein the air is separated by membrane separation.
 4321. The method of claim 4310, wherein fluids produced during pyrolysis of a relatively permeable formation containing heavy hydrocarbons comprise ammonia and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.
 4322. The method of claim 4310, wherein fluids produced during pyrolysis of a hydrocarbon formation are hydrotreated and at least some ammonia is produced during hydrotreating, and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.
 4323. The method of claim 4310, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea.
 4324. The method of claim 4310, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising providing carbon dioxide from the formation to the urea synthesis process.
 4325. The method of claim 4310, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising shifting at least a portion of the carbon monoxide to carbon dioxide in a shift process, and further comprising providing at least a portion of the carbon dioxide from the shift process to the urea synthesis process.
 4326. The method of claim 4310, wherein heating the selected section of the formation to a temperature to support reaction of hydrocarbon containing material in the formation to form synthesis gas comprises: heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with O₂ in the O₂ rich stream; introducing the O₂ to the zones substantially by diffusion; allowing O₂ in the O₂ rich stream to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and transferring heat from the zones to the selected section.
 4327. The method of claim 4326, wherein temperatures sufficient to support reaction of hydrocarbon containing material within the zones with O₂ range from approximately 200° C. to approximately 1200° C.
 4328. The method of claim 4326, wherein the one or more heat sources comprises one or more electrical heaters disposed in the formation.
 4329. The method of claim 4326, wherein the one or more heat sources comprises one or more natural distributed combustors.
 4330. The method of claim 4326, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 4331. The method of claim 4326, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 4332. The method of claim 4310, wherein heating the selected section of the formation to a temperature to support reaction of hydrocarbon containing material in the formation to form synthesis gas comprises: introducing the O₂ rich stream into the formation through a wellbore; transporting O₂ in the O₂ rich stream substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with O₂ in the O₂ rich stream; and reacting the O₂ within the portion of the selected section to generate heat and raise the temperature of the portion.
 4333. The method of claim 4332, wherein the temperature sufficient to support an oxidation reaction with O₂ ranges from approximately 200° C. to approximately 1200° C.
 4334. The method of claim 4332, wherein the one or more heat sources comprises one or more electrical heaters disposed in the formation.
 4335. The method of claim 4332, wherein the one or more heat sources comprises one or more natural distributed combustors.
 4336. The method of claim 4332, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 4337. The method of claim 4332, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 4338. The method of claim 4310, further comprising controlling the heating of at least the portion of the selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.
 4339. The method of claim 4310, wherein the synthesis gas generating fluid comprises liquid water.
 4340. The method of claim 4310, wherein the synthesis gas generating fluid comprises steam.
 4341. The method of claim 4310, wherein the synthesis gas generating fluid comprises water and carbon dioxide wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.
 4342. The method of claim 4341, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4343. The method of claim 4310, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 4344. The method of claim 4343, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4345. The method of claim 4310, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.
 4346. A method for producing ammonia using a relatively permeable formation containing heavy hydrocarbons, comprising: generating a first ammonia feed stream from a first portion of the formation; generating a second ammonia feed stream from a second portion of the formation, wherein the second ammonia feed stream has a 12 to N₂ ratio greater than a H₂ to N₂ ratio of the first ammonia feed stream; blending at least a portion of the first ammonia feed stream with at least a portion of the second ammonia feed stream to produce a blended ammonia feed stream having a selected H₂ to N₂ ratio; providing the blended ammonia feed stream to an ammonia synthesis process; and using the ammonia synthesis process to generate ammonia.
 4347. The method of claim 4346, wherein the selected ratio is approximately 3:1.
 4348. The method of claim 4346, wherein the selected ratio ranges from approximately 2.8:1 to approximately 3.2:1.
 4349. The method of claim 4346, further comprising separating at least a portion of carbon dioxide in the first ammonia feed stream from at least a portion of the first ammonia feed stream.
 4350. The method of claim 4349, wherein the carbon dioxide is separated from the first ammonia feed stream by an amine separator.
 4351. The method of claim 4350, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process.
 4352. The method of claim 4346, further comprising separating at least a portion of carbon dioxide in the blended ammonia feed stream from at least a portion of the blended ammonia feed stream.
 4353. The method of claim 4352, wherein the carbon dioxide is separated from the blended ammonia feed stream by an amine separator.
 4354. The method of claim 4353, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process.
 4355. The method of claim 4346, further comprising separating at least a portion of carbon dioxide in the second ammonia feed stream from at least a portion of the second ammonia feed stream.
 4356. The method of claim 4355, wherein the carbon dioxide is separated from the second ammonia feed stream by an amine separator.
 4357. The method of claim 4356, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process.
 4358. The method of claim 4346, wherein fluids produced during pyrolysis of a relatively permeable formation containing heavy hydrocarbons comprise ammonia and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.
 4359. The method of claim 4346, wherein fluids produced during pyrolysis of a hydrocarbon formation are hydrotreated and at least some ammonia is produced during hydrotreating, and further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.
 4360. The method of claim 4346, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea.
 4361. The method of claim 4346, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising providing carbon dioxide from the formation to the urea synthesis process.
 4362. The method of claim 4346, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and further comprising shifting at least a portion of carbon monoxide in the blended ammonia feed stream to carbon dioxide in a shift process, and further comprising providing at least a portion of the carbon dioxide from the shift process to the urea synthesis process.
 4363. A method for producing ammonia using a relatively permeable formation containing heavy hydrocarbons, comprising: heating a selected section of the formation to a temperature sufficient to support reaction of hydrocarbon containing material in the formation to form synthesis gas; providing a synthesis gas generating fluid and an O₂ rich stream to the selected section, wherein the amount of N₂ in the O₂ rich stream is sufficient to generate synthesis gas having a selected ratio of H₂ to N₂; allowing the synthesis gas generating fluid and O₂ in the O₂ rich stream to react with at least a portion of the hydrocarbon containing material in the formation to generate synthesis gas having a selected ratio of H₂ to N₂; producing the synthesis gas from the formation; providing at least a portion of the H₂ and N₂ in the synthesis gas to an ammonia synthesis process; using the ammonia synthesis process to generate ammonia.
 4364. The method of claim 4363, further comprising controlling a temperature of at least a portion of the selected section to generate synthesis gas having the selected H₂ to N₂ ratio.
 4365. The method of claim 4363, wherein the selected ratio is approximately 3:1.
 4366. The method of claim 4363, wherein the selected ratio ranges from approximately 2.8:1 to 3.2:1.
 4367. The method of claim 4363, wherein the temperature sufficient to support reaction of hydrocarbon containing material in the formation to form synthesis gas ranges from approximately 400° C. to approximately 1200° C.
 4368. The method of claim 4363, wherein the O₂ stream and N₂ stream are obtained by cryogenic separation of air.
 4369. The method of claim 4363, wherein the O₂ stream and N₂ stream are obtained by membrane separation of air.
 4370. The method of claim 4363, further comprising separating at least a portion of carbon dioxide in the synthesis gas from at least a portion of the synthesis gas.
 4371. The method of claim 4370, wherein the carbon dioxide is separated from the synthesis gas by an amine separator.
 4372. The method of claim 4371, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process.
 4373. The method of claim 4363, wherein fluids produced during pyrolysis of a relatively permeable formation containing heavy hydrocarbons comprise ammonia and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.
 4374. The method of claim 4363, wherein fluids produced during pyrolysis of a hydrocarbon formation are hydrotreated and at least some ammonia is produced during hydrotreating, and further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.
 4375. The method of claim 4363, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea.
 4376. The method of claim 4363, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising providing carbon dioxide from the formation to the urea synthesis process.
 4377. The method of claim 4363, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and further comprising shifting at least a portion of carbon monoxide in the synthesis gas to carbon dioxide in a shift process, and further comprising providing at least a portion of the carbon dioxide from the shift process to the urea synthesis process.
 4378. The method of claim 4363, wherein heating a selected section of the formation to a temperature to support reaction of hydrocarbon containing material in the formation to form synthesis gas comprises: heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with O₂ in the O₂ rich stream; introducing the O₂ to the zones substantially by diffusion; allowing O₂ in the O₂ rich stream to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and transferring heat from the zones to the selected section.
 4379. The method of claim 4378, wherein temperatures sufficient to support reaction of hydrocarbon containing material within the zones with O₂ range from approximately 200° C. to approximately 1200° C.
 4380. The method of claim 4378, wherein the one or more heat sources comprises one or more electrical heaters disposed in the formation.
 4381. The method of claim 4378, wherein the one or more heat sources comprises one or more natural distributed combustors.
 4382. The method of claim 4378, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 4383. The method of claim 4378, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 4384. The method of claim 4363, wherein heating the selected section of the formation to a temperature to support reaction of hydrocarbon containing material in the formation to form synthesis gas comprises: introducing the O₂ rich stream into the formation through a wellbore; transporting O₂ in the O₂ rich stream substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with O₂ in the O₂ rich stream; and reacting the O₂ within the portion of the selected section to generate heat and raise the temperature of the portion.
 4385. The method of claim 4384, wherein the temperature sufficient to support an oxidation reaction with O₂ ranges from approximately 200° C. to approximately 1200° C.
 4386. The method of claim 4384, wherein the one or more heat sources comprises one or more electrical heaters disposed in the formation.
 4387. The method of claim 4384, wherein the one or more heat sources comprises one or more natural distributed combustors.
 4388. The method of claim 4384, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.
 4389. The method of claim 4384, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.
 4390. The method of claim 4363, further comprising controlling the heating of at least the portion of the selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.
 4391. The method of claim 4363, wherein the synthesis gas generating fluid comprises liquid water.
 4392. The method of claim 4363, wherein the synthesis gas generating fluid comprises steam.
 4393. The method of claim 4363, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.
 4394. The method of claim 4393, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4395. The method of claim 4363, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.
 4396. The method of claim 4395, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.
 4397. The method of claim 4363, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.
 4398. A method for producing ammonia using a relatively permeable formation containing heavy hydrocarbons, comprising: providing a first stream comprising N₂ and carbon dioxide to the formation; allowing at least a portion of the carbon dioxide in the first stream to adsorb in the formation; producing a second stream from the formation, wherein the second stream comprises a lower percentage of carbon dioxide than the first stream, providing at least a portion of the N₂ in the second stream to an ammonia synthesis process.
 4399. The method of claim 4398, wherein the second stream comprises H₂ from the formation.
 4400. The method of claim 4398, wherein the first stream is produced from a relatively permeable formation containing heavy hydrocarbons.
 4401. The method of claim 4400, wherein the first stream is generated by reacting a oxidizing fluid with hydrocarbon containing material in the formation.
 4402. The method of claim 4398, wherein the second stream comprises H₂ from the formation and, further comprising providing such H₂ to the ammonia synthesis process.
 4403. The method of claim 4398, further comprising using the ammonia synthesis process to generate ammonia.
 4404. The method of claim 4403, wherein fluids produced during pyrolysis of a relatively permeable formation containing heavy hydrocarbons comprise ammonia and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.
 4405. The method of claim 4403, wherein fluids produced during pyrolysis of a hydrocarbon formation are hydrotreated and at least some ammonia is produced during hydrotreating, and further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.
 4406. The method of claim 4403, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea.
 4407. The method of claim 4403, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising providing carbon dioxide from the formation to the urea synthesis process.
 4408. The method of claim 4403, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and further comprising shifting at least a portion of carbon monoxide in the synthesis gas to carbon dioxide in a shift process, and further comprising providing at least a portion of the carbon dioxide from the shift process to the urea synthesis process.
 4409. A method of treating a hydrocarbon containing permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the permeable formation; allowing the heat to transfer from the one or more heat sources to a selected mobilization section of the permeable formation such that the heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected mobilization section of the permeable formation is less than about 150° C.; allowing the heat to transfer from the one or more heat sources to a selected pyrolyzation section of the permeable formation such that the heat from the one or more heat sources can pyrolyze at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected pyrolyzation section of the permeable formation is less than about 375° C.; and producing a mixture from the permeable formation.
 4410. The method of claim 4409, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation.
 4411. The method of claim 4409, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation.
 4412. The method of claim 4409, wherein the one or more heat sources comprise electrical heaters.
 4413. The method of claim 4409, wherein the one or more heat sources comprise surface burners.
 4414. The method of claim 4409, wherein the one or more heat sources comprise flameless distributed combustors.
 4415. The method of claim 4409, wherein the one or more heat sources comprise natural distributed combustors.
 4416. The method of claim 4409, further comprising disposing the one or more heat sources horizontally within the permeable formation.
 4417. The method of claim 4409, further comprising controlling a pressure and a temperature within at least a majority of the permeable formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 4418. The method of claim 4409, further comprising controlling the heat such that an average heating rate of the selected pyrolyzation section is less than about 15° C./day during pyrolysis.
 4419. The method of claim 4409, wherein providing heat from the one or more heat sources to at least the portion of permeable formation comprises: heating a selected volume (V) of the hydrocarbon containing permeable formation from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating late is less than about 10° C./day.
 4420. The method of claim 4409, wherein allowing the heat to transfer from the one or more heat sources to the selected mobilization section and/or the selected pyrolyzation section comprises transferring heat substantially by conduction.
 4421. The method of claim 4409, wherein producing the mixture from the permeable formation further comprises producing mixture having an API gravity of at least about 25°.
 4422. The method of claim 4409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is nitrogen.
 4423. The method of claim 4409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is oxygen.
 4424. The method of claim 4409, wherein the produced mixture comprises sulfur, and wherein less than about 5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is sulfur.
 4425. The method of claim 4409, further comprising controlling a pressure within at least a majority of the permeable formation, wherein the controlled pressure is at least about 2 bars absolute.
 4426. The method of claim 4409, further comprising altering a pressure within the permeable formation to inhibit production of hydrocarbons from the permeable formation having carbon numbers greater than about
 25. 4427. The method of claim 4409, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 4428. The method of claim 4409, wherein the produced mixture comprises condensable hydrocarbons and hydrogen, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 4429. The method of claim 4409, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein at least about 4 heat sources are disposed in the permeable formation for each production well.
 4430. The method of claim 4409, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein the production well is disposed substantially horizontally within the permeable formation.
 4431. The method of claim 4409, further comprising separating the mixture into a gas stream and a liquid stream.
 4432. The method of claim 4409, further comprising separating the mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 4433. The method of claim 4409, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 4434. The method of claim 4409, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the permeable formation adjacent to the wellbore, and further comprising heating the permeable formation with the heater element to produce the mixture, wherein the mixture comprises non-condensable hydrocarbons and H₂.
 4435. The method of claim 4409, wherein a minimum mobilization temperature is about 75° C.
 4436. The method of claim 4409, wherein a minimum pyrolysis temperature is about 270° C.
 4437. The method of claim 4409, further comprising maintaining the pressure within the permeable formation above about 2 bars absolute to inhibit production of fluids having carbon numbers above
 25. 4438. The method of claim 4409, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an amount of condensable fluids within the mixture, wherein the pressure is reduced to increase production of condensable fluids, and wherein the pressure is increased to increase production of non-condensable fluids.
 4439. The method of claim 4409, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an API gravity of condensable fluids within the mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.
 4440. The method of claim 4409, wherein mobilizing the hydrocarbons within the selected mobilization section comprises reducing a viscosity of the hydrocarbons.
 4441. The method of claim 4409, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation.
 4442. The method of claim 4409, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, and wherein the gas comprises carbon dioxide.
 4443. The method of claim 4409, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, and wherein the gas comprises nitrogen.
 4444. The method of claim 4409, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, the method further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled.
 4445. The method of claim 4409, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, the method further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is above about 2 bars absolute.
 4446. The method of claim 4409, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, the method further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is below about 70 bars absolute.
 4447. A method of treating a hydrocarbon containing permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the permeable formation; allowing the heat to transfer from the one or more heat sources to a selected mobilization section of the permeable formation such that the heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected mobilization section of the permeable formation is less than about 150° C.; allowing the heat to transfer from the one or more heat sources to a selected pyrolyzation section of the permeable formation such that the heat from the one or more heat sources can pyrolyze at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected pyrolyzation section of the permeable formation is less than about 375° C.; allowing at least some of the mobilized hydrocarbons to flow from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation; and producing a mixture from the permeable formation.
 4448. The method of claim 4447, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation.
 4449. The method of claim 4447, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can pyrolyze at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation.
 4450. The method of claim 4447, wherein the one or more heat sources comprise electrical heaters.
 4451. The method of claim 4447, wherein the one or more heat sources comprise surface burners.
 4452. The method of claim 4447, wherein the one or more heat sources comprise flameless distributed combustors.
 4453. The method of claim 4447, wherein the one or more heat sources comprise natural distributed combustors.
 4454. The method of claim 4447, further comprising disposing the one or more heat sources horizontally within the permeable formation.
 4455. The method of claim 4447, further comprising controlling a pressure and a temperature within at least a majority of the permeable formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 4456. The method of claim 4447, further comprising controlling the heat such that an average heating rate of the selected pyrolyzation section is less than about 15° C./day during pyrolysis.
 4457. The method of claim 4447, wherein providing heat from the one or more heat sources to at least the portion of permeable formation comprises: heating a selected volume (V) of the hydrocarbon containing permeable formation from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 4458. The method of claim 4447, wherein allowing the heat to transfer from the one or more heat sources to the selected mobilization section and/or the selected pyrolyzation section comprises transferring heat substantially by conduction.
 4459. The method of claim 4447, wherein producing the mixture from the permeable formation further comprises producing a mixture having an API gravity of at least about 25°.
 4460. The method of claim 4447, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is nitrogen.
 4461. The method of claim 4447, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is oxygen.
 4462. The method of claim 4447, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is sulfur.
 4463. The method of claim 4447, further comprising controlling a pressure within at least a majority of the permeable formation, wherein the controlled pressure is at least about 2 bars absolute.
 4464. The method of claim 4447, further comprising altering a pressure within the permeable formation to inhibit production of hydrocarbons from the permeable formation having carbon numbers greater than about
 25. 4465. The method of claim 4447, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 4466. The method of claim 4447, wherein the produced mixture comprises condensable hydrocarbons and hydrogen, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 4467. The method of claim 4447, wherein producing the mixture from the permeable formation further comprises producing mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein at least about 4 heat sources are disposed in the permeable formation for each production well.
 4468. The method of claim 4447, wherein producing the mixture from the permeable formation further comprises producing mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein the production well is disposed substantially horizontally within the permeable formation.
 4469. The method of claim 4447, further comprising separating the mixture into a gas stream and a liquid stream.
 4470. The method of claim 4447, further comprising separating the mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 4471. The method of claim 4447, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 4472. The method of claim 4447, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the permeable formation adjacent to the wellbore, and further comprising heating the permeable formation with the heater element to produce the mixture, wherein the mixture comprises non-condensable hydrocarbons and H₂.
 4473. The method of claim 4447, wherein a minimum mobilization temperature is about 75° C.
 4474. The method of claim 4447, wherein a minimum pyrolysis temperature is about 270° C.
 4475. The method of claim 4447, further comprising maintaining the pressure within the permeable formation above about 2 bars absolute to inhibit production of fluids having carbon numbers above
 25. 4476. The method of claim 4447, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an amount of condensable fluids within the mixture, wherein the pressure is reduced to increase production of condensable fluids, and wherein the pressure is increased to increase production of non-condensable fluids.
 4477. The method of claim 4447, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an API gravity of condensable fluids within the mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.
 4478. The method of claim 4447, wherein mobilizing the hydrocarbons within the selected mobilization section comprises reducing a viscosity of the hydrocarbons.
 4479. The method of claim 4447, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation.
 4480. The method of claim 4447, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, and wherein the gas comprises carbon dioxide.
 4481. The method of claim 4447, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, and wherein the gas comprises nitrogen.
 4482. The method of claim 4447, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, the method further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled.
 4483. The method of claim 4447, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, the method further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is above about 2 bars absolute.
 4484. The method of claim 4447, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, the method further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is below about 100 bars absolute.
 4485. A method of treating a hydrocarbon containing permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the permeable formation; allowing the heat to transfer from the one or more heat sources to a selected mobilization section of the permeable formation such that the heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected mobilization section of the permeable formation is less than about 150° C.; allowing the heat to transfer from the one or more heat sources to a selected pyrolyzation section of the permeable formation such that the heat from the one or more heat sources can pyrolyze at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected pyrolyzation section of the permeable formation is less than about 375° C.; allowing at least some of the mobilized hydrocarbons to flow from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation; providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation; and producing a mixture from the permeable formation.
 4486. The method of claim 4485, wherein the one or more heat sources comprise at least two heat sources, and wherein the heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation.
 4487. The method of claim 4485, wherein the one or more heat sources comprise at least two heat sources, and wherein the heat from the one or more heat sources can pyrolyze at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation.
 4488. The method of claim 4485, wherein the one or more heat sources comprise electrical heaters.
 4489. The method of claim 4485, wherein the one or more heat sources comprise surface burners.
 4490. The method of claim 4485, wherein the one or more heat sources comprise flameless distributed combustors.
 4491. The method of claim 4485, wherein the one or more heat sources comprise natural distributed combustors.
 4492. The method of claim 4485, further comprising disposing the one or more heat sources horizontally within the permeable formation.
 4493. The method of claim 4485, further comprising controlling a pressure and a temperature within at least a majority of the permeable formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 4494. The method of claim 4485, further comprising controlling the heat such that an average heating rate of the selected pyrolyzation section is less than about 15° C./day during pyrolysis.
 4495. The method of claim 4485, wherein providing heat from the one or more heat sources to at least the portion of permeable formation comprises: heating a selected volume (V) of the hydrocarbon containing permeable formation from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 4496. The method of claim 4485, wherein allowing the heat to transfer from the one or more heat sources to the selected mobilization section and/or the selected pyrolyzation section comprises transferring heat substantially by conduction.
 4497. The method of claim 4485, wherein producing mixture from the permeable formation further comprises producing mixture having an API gravity of at least about 25°.
 4498. The method of claim 4485, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is nitrogen.
 4499. The method of claim 4485, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is oxygen.
 4500. The method of claim 4485, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is sulfur.
 4501. The method of claim 4485, further comprising controlling a pressure within at least a majority of the permeable formation, wherein the controlled pressure is at least about 2 bars absolute.
 4502. The method of claim 4485, further comprising altering a pressure within the permeable formation to inhibit production of hydrocarbons from the permeable formation having carbon numbers greater than about
 25. 4503. The method of claim 4485, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 4504. The method of claim 4485, wherein the produced mixture comprises condensable hydrocarbons and hydrogen, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 4505. The method of claim 4485, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein at least about 4 heat sources are disposed in the permeable formation for each production well.
 4506. The method of claim 4485, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein the production well is disposed substantially horizontally within the permeable formation.
 4507. The method of claim 4485, further comprising separating the mixture into a gas stream and a liquid stream.
 4508. The method of claim 4485, further comprising separating the mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 4509. The method of claim 4485, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 4510. The method of claim 4485, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the permeable formation adjacent to the wellbore, and further comprising heating the permeable formation with the heater element to produce the mixture, wherein the mixture comprise non-condensable hydrocarbons and H₂.
 4511. The method of claim 4485, wherein a minimum mobilization temperature is about 75° C.
 4512. The method of claim 4485, wherein a minimum pyrolysis temperature is about 270° C.
 4513. The method of claim 4485, further comprising maintaining the pressure within the permeable formation above about 2 bars absolute to inhibit production of fluids having carbon numbers above
 25. 4514. The method of claim 4485, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an amount of condensable fluids within the mixture, wherein the pressure is reduced to increase production of condensable fluids, and wherein the pressure is increased to increase production of non-condensable fluids.
 4515. The method of claim 4485, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an API gravity of condensable fluids within the mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.
 4516. The method of claim 4485, wherein mobilizing the hydrocarbons within the selected mobilization section comprises reducing a viscosity of the hydrocarbons.
 4517. The method of claim 4485, wherein the provided gas comprises carbon dioxide.
 4518. The method of claim 4485, wherein the provided gas comprises nitrogen.
 4519. The method of claim 4485, further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled.
 4520. The method of claim 4485, further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is above about 2 bars absolute.
 4521. The method of claim 4485, further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is below about 100 bars absolute.
 4522. A method of treating a hydrocarbon containing permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the permeable formation; allowing the heat to transfer from the one or more heat sources to a selected mobilization section of the permeable formation such that the heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected mobilization section of the permeable formation is less than about 150° C.; allowing the heat to transfer from the one or more heat sources to a selected pyrolyzation section of the permeable formation such that the heat from the one or more heat sources can pyrolyze at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected pyrolyzation section of the permeable formation is less than about 375° C.; allowing at least some of the mobilized hydrocarbons to flow from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation; providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation; controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled; and producing a mixture from the permeable formation.
 4523. The method of claim 4522, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation.
 4524. The method of claim 4522, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can pyrolyze at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation.
 4525. The method of claim 4522, wherein the one or more heat sources comprise electrical heaters.
 4526. The method of claim 4522, wherein the one or more heat sources comprise surface burners.
 4527. The method of claim 4522, wherein the one or more heat sources comprise flameless distributed combustors.
 4528. The method of claim 4522, wherein the one or more heat sources comprise natural distributed combustors.
 4529. The method of claim 4522, further comprising disposing the one or more heat sources horizontally within the permeable formation.
 4530. The method of claim 4522, further comprising controlling a pressure and a temperature within at least a majority of the permeable formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 4531. The method of claim 4522, further comprising controlling the heat such that an average heating rate of the selected pyrolyzation section is less than about 15° C./day during pyrolysis.
 4532. The method of claim 4522, wherein providing heat from the one or more heat sources to at least the portion of permeable formation comprises: heating a selected volume (V) of the hydrocarbon containing permeable formation from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 4533. The method of claim 4522, wherein allowing the heat to transfer from the one or more heat sources to the selected mobilization section and/or the selected pyrolyzation section comprises transferring heat substantially by conduction.
 4534. The method of claim 4522, wherein producing the mixture from the permeable formation further comprises producing mixture having an API gravity of at least about 25°.
 4535. The method of claim 4522, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is nitrogen.
 4536. The method of claim 4522, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is oxygen.
 4537. The method of claim 4522, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is sulfur.
 4538. The method of claim 4522, further comprising controlling a pressure within at least a majority of the permeable formation, wherein the controlled pressure is at least about 2 bars absolute.
 4539. The method of claim 4522, further comprising altering a pressure within the permeable formation to inhibit production of hydrocarbons from the permeable formation having carbon numbers greater than about
 25. 4540. The method of claim 4522, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 4541. The method of claim 4522, wherein the produced mixture comprises condensable hydrocarbons and hydrogen, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 4542. The method of claim 4522, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein at least about 4 heat sources are disposed in the permeable formation for each production well.
 4543. The method of claim 4522, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein the production well is disposed substantially horizontally within the permeable formation.
 4544. The method of claim 4522, further comprising separating the mixture into a gas stream and a liquid stream.
 4545. The method of claim 4522, further comprising separating the mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 4546. The method of claim 4522, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 4547. The method of claim 4522, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the permeable formation adjacent to the wellbore, and further comprising heating the permeable formation with the heater element to produce the mixture, wherein the mixture comprises non-condensable hydrocarbons and
 12. 4548. The method of claim 4522, wherein a minimum mobilization temperature is about 75° C.
 4549. The method of claim 4522, wherein a minimum pyrolysis temperature is about 270° C.
 4550. The method of claim 4522, further comprising maintaining the pressure within the permeable formation above about 2 bars absolute to inhibit production of fluids having carbon numbers above
 25. 4551. The method of claim 4522, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an amount of condensable fluids within the mixture, wherein the pressure is reduced to increase production of condensable fluids, and wherein the pressure is increased to increase production of non-condensable fluids.
 4552. The method of claim 4522, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an API gravity of condensable fluids within the mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.
 4553. The method of claim 4522, wherein mobilizing the hydrocarbons within the selected mobilization section comprises reducing a viscosity of the hydrocarbons.
 4554. The method of claim 4522, wherein the provided gas comprises carbon dioxide.
 4555. The method of claim 4522, wherein the provided gas comprises nitrogen.
 4556. The method of claim 4522, wherein the pressure of the provided gas is above about 2 bars absolute.
 4557. The method of claim 4522, wherein the pressure of the provided gas is below about 70 bars absolute.
 4558. A method of treating a hydrocarbon containing permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the permeable formation; allowing the heat to transfer from the one or more heat sources to a selected mobilization section of the permeable formation such that the heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected mobilization section of the permeable formation is less than about 150° C.; allowing the heat to transfer from the one or more heat sources to a selected pyrolyzation section of the permeable formation such that the heat from the one or more heat sources can pyrolyze at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected pyrolyzation section of the permeable formation is less than about 375° C.; and producing a mixture from the permeable formation in a production well, wherein the production well is disposed substantially horizontally within the permeable formation.
 4559. The method of claim 4558, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation.
 4560. The method of claim 4558, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can pyrolyze at least some of the hydrocarbons within the selected pyrolyzation section of the permeable formation.
 4561. The method of claim 4558, wherein the one or more heat sources comprise electrical heaters.
 4562. The method of claim 4558, wherein the one or more heat sources comprise surface burners.
 4563. The method of claim 4558, wherein the one or more heat sources comprise flameless distributed combustors.
 4564. The method of claim 4558, wherein the one or more heat sources comprise natural distributed combustors.
 4565. The method of claim 4558, further comprising disposing the one or more heat sources horizontally within the permeable formation.
 4566. The method of claim 4558, further comprising controlling a pressure and a temperature within at least a majority of the permeable formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 4567. The method of claim 4558, further comprising controlling the heat such that an average heating rate of the selected pyrolyzation section is less than about 15° C./day during pyrolysis.
 4568. The method of claim 4558, wherein providing heat from the one or more heat sources to at least the portion of permeable formation comprises: heating a selected volume (V) of the hydrocarbon containing permeable formation from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 4569. The method of claim 4558, wherein allowing the heat to transfer from the one or more heat sources to the selected mobilization section and/or the selected pyrolyzation section comprises transferring heat substantially by conduction.
 4570. The method of claim 4558, wherein producing mixture from the permeable formation further comprises producing mixture having an API gravity of at least about 25°.
 4571. The method of claim 4558, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is nitrogen.
 4572. The method of claim 4558, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is oxygen.
 4573. The method of claim 4558, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight, of the condensable hydrocarbons, when calculated on an atomic basis, is sulfur.
 4574. The method of claim 4558, further comprising controlling a pressure within at least a majority of the permeable formation, wherein the controlled pressure is at least about 2 bars absolute.
 4575. The method of claim 4558, further comprising altering a pressure within the permeable formation to inhibit production of hydrocarbons from the permeable formation having carbon numbers greater than about
 25. 4576. The method of claim 4558, further comprising: providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and heating a portion of the section with heat from hydrogenation.
 4577. The method of claim 4558, wherein the produced mixture comprises condensable hydrocarbons and hydrogen, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.
 4578. The method of claim 4558, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein at least about 4 heat sources are disposed in the permeable formation for each production well.
 4579. The method of claim 4558, further comprising separating the mixture into a gas stream and a liquid stream.
 4580. The method of claim 4558, further comprising separating the mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 4581. The method of claim 4558, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 4582. The method of claim 4558, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the permeable formation adjacent to the wellbore, and further comprising heating the permeable formation with the heater element to produce the mixture, wherein the mixture comprises non-condensable hydrocarbons and H₂.
 4583. The method of claim 4558, wherein a minimum mobilization temperature is about 75° C.
 4584. The method of claim 4558, wherein a minimum pyrolysis temperature is about 270° C.
 4585. The method of claim 4558, further comprising maintaining the pressure within the permeable formation above about 2 bars absolute to inhibit production of fluids having carbon numbers above
 25. 4586. The method of claim 4558, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an amount of condensable fluids within the mixture, wherein the pressure is reduced to increase production of condensable fluids, and wherein the pressure is increased to increase production of non-condensable fluids.
 4587. The method of claim 4558, further comprising controlling pressure within the permeable formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an API gravity of condensable fluids within the mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.
 4588. The method of claim 4558, wherein mobilizing the hydrocarbons within the selected mobilization section comprises reducing a viscosity of the hydrocarbons.
 4589. The method of claim 4558, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation.
 4590. The method of claim 4558, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, and wherein the gas comprises carbon dioxide.
 4591. The method of claim 4558, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, and wherein the gas comprises nitrogen.
 4592. The method of claim 4558, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, the method further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled.
 4593. The method of claim 4558, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, the method further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is above about 2 bars absolute.
 4594. The method of claim 4558, further comprising providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons from the selected mobilization section of the permeable formation to the selected pyrolyzation section of the permeable formation, the method further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is below about 70 bars absolute.
 4595. A method of treating a hydrocarbon containing permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the permeable formation; allowing the heat to transfer from the one or more heat sources to a selected mobilization section of the permeable formation such that the heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected mobilization section of the permeable formation is less than about 150° C.; providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons within the permeable formation; and producing a mixture from the permeable formation.
 4596. The method of claim 4595, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation.
 4597. The method of claim 4595, wherein the one or more heat sources comprise electrical heaters.
 4598. The method of claim 4595, wherein the one or more heat sources comprise surface burners.
 4599. The method of claim 4595, wherein the one or more heat sources comprise flameless distributed combustors.
 4600. The method of claim 4595, wherein the one or more heat sources comprise natural distributed combustors.
 4601. The method of claim 4595, further comprising disposing the one or more heat sources horizontally within the permeable formation.
 4602. The method of claim 4595, further comprising controlling a pressure and a temperature within at least a majority of the permeable formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 4603. The method of claim 4595, wherein providing heat from the one or more heat sources to at least the portion of permeable formation comprises: heating a selected volume (V) of the hydrocarbon containing permeable formation from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 4604. The method of claim 4595, wherein allowing the heat to transfer from the one or more heat sources to the selected mobilization section comprises transferring heat substantially by conduction.
 4605. The method of claim 4595, further comprising controlling a pressure within at least a majority of the permeable formation, wherein the controlled pressure is at least about 2 bars absolute.
 4606. The method of claim 4595, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein at least about 4 heat sources are disposed in the permeable formation for each production well.
 4607. The method of claim 4595, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein the production well is disposed substantially horizontally within the permeable formation.
 4608. The method of claim 4595, further comprising separating the mixture into a gas stream and a liquid stream.
 4609. The method of claim 4595, further comprising separating the mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 4610. The method of claim 4595, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 4611. The method of claim 4595, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the permeable formation adjacent to the wellbore, and further comprising heating the permeable formation with the heater element to produce the mixture, wherein the mixture comprise non-condensable hydrocarbons and H₂.
 4612. The method of claim 4595, wherein a minimum mobilization temperature is about 75° C.
 4613. The method of claim 4595, wherein mobilizing the hydrocarbons within the selected mobilization section comprises reducing a viscosity of the hydrocarbons.
 4614. The method of claim 4595, wherein the provided gas comprises carbon dioxide.
 4615. The method of claim 4595, wherein the provided gas comprises nitrogen.
 4616. The method of claim 4595, further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled.
 4617. The method of claim 4595, further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is above about 2 bars absolute.
 4618. The method of claim 4595, further comprising controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled, wherein the pressure of the provided gas is below about 70 bars absolute.
 4619. A method of treating a hydrocarbon containing permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the permeable formation; allowing the heat to transfer from the one or more heat sources to a selected mobilization section of the permeable formation such that the heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected mobilization section of the permeable formation is less than about 150° C.; providing a gas to the permeable formation, wherein the gas is configured to increase a flow of the mobilized hydrocarbons within the permeable formation; controlling a pressure of the provided gas such that the flow of the mobilized hydrocarbons is controlled; and producing a mixture from the permeable formation.
 4620. The method of claim 4619, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from the one or more heat sources can mobilize at least some of the hydrocarbons within the selected mobilization section of the permeable formation.
 4621. The method of claim 4619, wherein the one or more heat sources comprise electrical heaters.
 4622. The method of claim 4619, wherein the one or more heat sources comprise surface burners.
 4623. The method of claim 4619, wherein the one or more heat sources comprise flameless distributed combustors.
 4624. The method of claim 4619, wherein the one or more heat sources comprise natural distributed combustors.
 4625. The method of claim 4619, further comprising disposing the one or more heat sources horizontally within the permeable formation.
 4626. The method of claim 4619, further comprising controlling a pressure and a temperature within at least a majority of the permeable formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 4627. The method of claim 4619, wherein providing heat from the one or more heat sources to at least the portion of permeable formation comprises: heating a selected volume (V) of the hydrocarbon containing permeable formation from the one or more heat sources, wherein the formation has an average heat capacity (C_(v)), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ_(B) is formation bulk density, and wherein the heating rate is less than about 10° C./day.
 4628. The method of claim 4619, wherein allowing the heat to transfer from the one or more heat sources to the selected mobilization section comprises transferring heat substantially by conduction.
 4629. The method of claim 4619, further comprising controlling a pressure within at least a majority of the permeable formation, wherein the controlled pressure is at least about 2 bars absolute.
 4630. The method of claim 4619, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein at least about 4 heat sources are disposed in the permeable formation for each production well.
 4631. The method of claim 4619, wherein producing the mixture from the permeable formation further comprises producing the mixture in a production well, wherein the heating is controlled such that the mixture can be produced from the permeable formation, and wherein the production well is disposed substantially horizontally within the permeable formation.
 4632. The method of claim 4619, further comprising separating the mixture into a gas stream and a liquid stream.
 4633. The method of claim 4619, further comprising separating the mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.
 4634. The method of claim 4619, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 4635. The method of claim 4619, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the permeable formation adjacent to the wellbore, and further comprising heating the permeable formation with the heater element to produce the mixture, wherein the mixture comprise non-condensable hydrocarbons and H₂.
 4636. The method of claim 4619, wherein a minimum mobilization temperature is about 75° C.
 4637. The method of claim 4619, wherein mobilizing the hydrocarbons within the selected mobilization section comprises reducing a viscosity of the hydrocarbons.
 4638. The method of claim 4619, wherein the provided gas comprises carbon dioxide.
 4639. The method of claim 4619, wherein the provided gas comprises nitrogen.
 4640. The method of claim 4619, wherein the pressure of the provided gas is above about 2 bars absolute.
 4641. The method of claim 4619, wherein the pressure of the provided gas is below about 70 bars absolute.
 4642. A system configurable to heat a relatively permeable formation, comprising: a conduit configurable to be placed within an opening in the formation; a conductor configurable to be placed within the conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use; at least one centralizer configurable to be coupled to the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit during use; and wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use.
 4643. The system of claim 4642, wherein at least one centralizer comprises electrically-insulating material.
 4644. The system of claim 4642, wherein at least one centralizer is configurable to inhibit arcing between the conductor and the conduit.
 4645. The system of claim 4642, wherein at least one centralizer comprises ceramic material.
 4646. The system of claim 4642, wherein at least one centralizer comprises at least one recess, wherein at least one recess is placed at a junction of at least one centralizer and the first conductor, wherein at least one protrusion is formed on the first conductor at the junction to maintain a location of at least one centralizer on the first conductor, and wherein at least one protrusion resides substantially within at least one recess.
 4647. The system of claim 4646, wherein at least one protrusion comprises a weld.
 4648. The system of claim 4646, wherein an electrically-insulating material substantially covers at least one recess.
 4649. The system of claim 4646, wherein a thermal plasma applied coating substantially covers at least one recess.
 4650. The system of claim 4646, wherein a thermal plasma applied coating comprises alumina.
 4651. The system of claim 4642, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.
 4652. The system of claim 4642, further comprising an insulation layer configurable to be coupled to at least a portion of the conductor or at least one centralizer.
 4653. The system of claim 4642, wherein at least one centralizer comprises a neck portion.
 4654. The system of claim 4642, wherein at least one centralizer comprises one or more grooves.
 4655. The system of claim 4642, wherein at least one centralizer comprises at least two portions, and wherein the portions are configurable to be coupled to the conductor to form at least one centralizer placed on the conductor.
 4656. The system of claim 4642, wherein a thickness of the conductor is greater adjacent to a lean zone in the formation than a thickness of the conductor adjacent to a rich zone in the formation such that more heat is provided to the rich zone.
 4657. The system of claim 4642, wherein the system is configured to heat a relatively permeable formation, and wherein the system comprises: a conduit configured to be placed within an opening in the formation; a conductor configured to be placed within the conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use; at least one centralizer configured to be coupled to the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit during use; and wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.
 4658. The system of claim 4642, wherein the system heats a relatively permeable formation, and wherein the system comprises: a conduit placed within an opening in the formation; a conductor placed within the conduit, wherein the conductor provides heat to at least a portion of the formation; at least one centralizer coupled to the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit; and wherein the system allows heat to transfer from the conductor to a section of the formation.
 4659. The system of claim 4642, wherein the system is configurable to be removed from the opening in the formation.
 4660. The system of claim 4642, further comprising a moveable thermocouple.
 4661. The system of claim 4642, further comprising an isolation block.
 4662. A system configurable to heat a relatively permeable formation, comprising: a conduit configurable to be placed within an opening in the formation; a conductor configurable to be placed within the conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use; at least one centralizer configurable to be coupled to the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit during use wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use; and wherein the system is configurable to be removed from the opening in the formation.
 4663. An in situ method for heating a relatively permeable formation, comprising: applying an electrical current to a conductor to provide heat to at least a portion of the formation, wherein the conductor is placed within a conduit, wherein at least one centralizer is coupled to the conductor to inhibit movement of the conductor within the conduit, and wherein the conduit is placed within an opening in the formation; and allowing the heat to transfer from the first conductor to a section of the formation.
 4664. The method of claim 4663, further comprising pyrolyzing at least some hydrocarbons in the section of the formation.
 4665. The method of claim 4663, further comprising inhibiting arcing between the conductor and the conduit.
 4666. A system configurable to heat a relatively permeable formation, comprising: a conduit configurable to be placed within an opening in the formation; a conductor configurable to be placed within a conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use; an insulation layer coupled to at least a portion of the conductor, wherein the insulation layer electrically insulates at least a portion of the conductor from the conduit during use; and wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use.
 4667. The system of claim 4666, wherein the insulation layer comprises a spiral insulation layer.
 4668. The system of claim 4666, wherein the insulation layer comprises at least one metal oxide.
 4669. The system of claim 4666, wherein the insulation layer comprises at least one alumina oxide.
 4670. The system of claim 4666, wherein the insulation layer is configurable to be fastened to the conductor with a high temperature glue.
 4671. The system of claim 4666, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.
 4672. The system of claim 4666, wherein the system is configured to heat a relatively permeable formation, and wherein the system comprises: a conduit configured to be placed within an opening in the formation; a conductor configured to be placed within a conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use; an insulation layer coupled to at least a portion of the conductor, wherein the insulation layer electrically insulates at least a portion of the conductor from the conduit during use; and wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.
 4673. The system of claim 4666, wherein the system heats a relatively permeable formation, and wherein the system comprises: a conduit placed within an opening in the formation; a conductor placed within a conduit, wherein the conductor provides heat to at least a portion of the formation; an insulation layer coupled to at least a portion of the conductor, wherein the insulation layer electrically insulates at least a portion of the conductor from the conduit; and wherein the system allows heat to transfer from the conductor to a section of the formation.
 4674. An in situ method for heating a relatively permeable formation, comprising: applying an electrical current to a conductor to provide heat to at least a portion of the formation, wherein the conductor is placed within a conduit, wherein an insulation layer is coupled to at least a portion of the conductor to electrically insulate at least a portion of the conductor from the conduit, and wherein the conduit is placed within an opening in the formation; and allowing the heat to transfer from the first conductor to a section of the formation.
 4675. The method of claim 4674, further comprising pyrolyzing at least some hydrocarbons in the section of the formation.
 4676. The method of claim 4674, further comprising inhibiting arcing between the conductor and the conduit.
 4677. A method for making a conductor-in-conduit heat source for a relatively permeable formation, comprising: placing at least one protrusion on a conductor; placing at least one centralizer on the conductor; and placing the conductor within a conduit to form a conductor-in-conduit heat source, wherein at least one centralizer maintains a location of the conductor within the conduit.
 4678. The method of claim 4677, wherein at least one centralizer comprises at least two portions, and wherein the portions are coupled to the conductor to form at least one centralizer placed on the conductor.
 4679. The method of claim 4677, further comprising placing the conductor-in-conduit heat source in an opening in a relatively permeable formation.
 4680. The method of claim 4677, further comprising coupling an insulation layer on the conductor, wherein the insulation layer is configured to electrically insulate at least a portion of the conductor from the conduit.
 4681. The method of claim 4677, further comprising providing heat from the conductor-in-conduit heat source to at least a portion of the formation.
 4682. The method of claim 4677, further comprising pyrolyzing at least some hydrocarbons in a selected section of the formation.
 4683. The method of claim 4677, further comprising producing a mixture from a selected section of the formation.
 4684. The method of claim 4677, wherein the conductor-in-conduit heat source is configurable to provide heat to the relatively permeable formation.
 4685. The method of claim 4677, wherein at least one centralizer comprises at least one recess placed at a junction of at least one centralizer on the conductor, and wherein at least one protrusion resides substantially within at least one recess.
 4686. The method of claim 4685, further comprising at least partially covering at least one recess with an electrically-insulating material.
 4687. The method of claim 4685, further comprising spraying an electrically-insulating material to at least partially cover at least one recess.
 4688. The method of claim 4677, wherein placing at least one protrusion on the conductor comprises welding at least one protrusion on the conductor.
 4689. The method of claim 4677, further comprising coiling the conductor-in-conduit heat source on a spool after forming the heat source.
 4690. The method of claim 4677, further comprising uncoiling the heat source from the spool while placing the heat source in an opening in the formation.
 4691. The method of claim 4677, wherein placing the conductor within a conduit comprises placing the conductor within a conduit that has been placed in an opening in the formation.
 4692. The method of claim 4677, further comprising coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source.
 4693. The method of claim 4677, wherein the conductor-in-conduit heat source is configurable to be installed into an opening in a relatively permeable formation.
 4694. The method of claim 4677, wherein the conductor-in-conduit heat source is configurable to be removed from an opening in a relatively permeable formation.
 4695. The method of claim 4677, wherein the conductor-in-conduit heat source is configurable to heat to a section of the relatively permeable formation, and wherein the heat pyrolyzes at least some hydrocarbons in the section of the formation during use.
 4696. The method of claim 4677, wherein a thickness of the conductor configurable to be placed adjacent to a lean zone in the formation is greater than a thickness of the conductor configurable to be placed adjacent to a rich zone in the formation such that more heat is provided to the rich zone during use.
 4697. A method for forming an opening in a relatively permeable formation, comprising: forming a first opening in the formation; providing a series of magnetic fields from a plurality of magnets positioned along a portion of the first opening; and forming a second opening in the formation using magnetic tracking such that the second opening is positioned a selected distance from the first opening.
 4698. The method of claim 4697, further comprising providing a magnetic string to a portion of the first opening.
 4699. The method of claim 4697, wherein the plurality of magnets is positioned within a casing.
 4700. The method of claim 4697, wherein the plurality of magnets is positioned within a heater casing.
 4701. The method of claim 4697, wherein the plurality of magnets is positioned within a perforated casing.
 4702. The method of claim 4697, further comprising providing a magnetic string to a portion of the first opening, wherein the magnetic string comprises two or more magnetic segments, and wherein the two or more segments are positioned such that the polarity of adjacent segments is reversed.
 4703. The method of claim 4697, further comprising moving the magnetic fields within the first opening.
 4704. The method of claim 4697, further comprising moving the magnetic fields within the first opening such that the magnetic fields vary with time.
 4705. The method of claim 4697, further comprising adjusting a position of the magnetic fields within the first opening to increase a length of the second opening.
 4706. The method of claim 4697, further comprising forming a plurality of openings adjacent to the first opening.
 4707. The method of claim 4697, wherein the first opening comprises a non-metallic casing.
 4708. The method of claim 4697, wherein the series of the magnetic fields comprises a first magnetic field and a second magnetic field and wherein a strength of the first magnetic differs from a strength of the second magnetic field.
 4709. The method of claim 4697, wherein the series of the magnetic fields comprises a first magnetic field and a second magnetic field and wherein a strength of the first magnetic is about a strength of the second magnetic field.
 4710. The method of claim 4697, wherein the first opening comprises a center opening in a pattern of openings, and further comprising forming a plurality of openings adjacent to the first opening.
 4711. The method of claim 4697, wherein the first opening comprises a center opening in a pattern of openings, and further comprising forming a plurality of openings adjacent to the first opening, wherein each of the plurality of openings is positioned at the selected distance from the first opening.
 4712. The method of claim 4697, further comprising providing at least one heating mechanism within the first opening and at least one heating mechanism within the second opening such that the heating mechanisms can provide heat to at least a portion of the formation.
 4713. A method for forming an opening in a relatively permeable formation, comprising: forming a first opening in the formation; providing a magnetic string to the first opening, wherein the magnetic string comprises two or more magnetic segments, and wherein the magnetic segments are positioned such that the polarities of the segments are reversed; and forming a second opening in the formation using magnetic tracking such that the second opening is positioned a selected distance from the first opening.
 4714. The method of claim 4713, further comprising providing at least one heating mechanism within the first opening and at least one heating mechanism within the second opening such that the heating mechanisms can provide heat to at least a portion of the formation.
 4715. The method of claim 4713, wherein the two or more segments comprise a plurality of magnets.
 4716. The method of claim 4713, further comprising providing a series of magnetic fields along a portion of the first opening.
 4717. The method of claim 4713, wherein a length of a segment corresponds to a distance between the first opening and the second opening.
 4718. The method of claim 4713, further comprising moving the magnetic fields within the first opening.
 4719. The method of claim 4713, further comprising moving the magnetic fields within the first opening such that the magnetic fields vary with time.
 4720. The method of claim 4713, further comprising adjusting a position of the magnetic fields within the first opening to increase a length of the second opening.
 4721. The method of claim 4713, further comprising forming a plurality of openings adjacent to the first opening.
 4722. The method of claim 4713, wherein the first opening comprises a non-metallic casing.
 4723. The method of claim 4713, wherein the series of the magnetic fields comprises a first magnetic field and a second magnetic field and wherein a strength of the first magnetic field differs from a strength of the second magnetic field.
 4724. The method of claim 4713, wherein the series of the magnetic fields comprises a first magnetic field and a second magnetic field and wherein a strength of the first magnetic field is about a strength of the second magnetic field.
 4725. The method of claim 4713, wherein the first opening comprises a center opening in a pattern of openings, and further comprising forming a plurality of openings adjacent to the first opening.
 4726. The method of claim 4713, wherein the first opening comprises a center opening in a pattern of openings, and further comprising forming a plurality of openings adjacent to the first opening, wherein each of the plurality of openings is positioned at the selected distance from the first opening.
 4727. The method of claim 4713, further comprising providing at least one heating mechanism within the first opening and at least one heating mechanism within the second opening such that the heating mechanisms can provide heat to at least a portion of the formation.
 4728. The method of claim 4713, wherein the magnetic string is positioned within a casing.
 4729. The method of claim 4713, wherein the magnetic string is positioned within a heater casing.
 4730. A system for drilling openings in a relatively permeable formation, comprising: a drilling apparatus; a magnetic string, comprising: a conduit; and two or more magnetic segments positionable in the conduit, wherein the magnetic segments comprise a plurality of magnets; and a sensor configurable to detect a magnetic field within the formation.
 4731. The system of claim 4730, wherein the magnetic string further comprises one or more members configurable to inhibit movement of the magnetic segments relative to the conduit.
 4732. The system of claim 4730, wherein the one or more magnetic segments are positioned such that a polarity of adjacent segments is reversed.
 4733. The system of claim 4730, wherein the magnetic string is positionable within a first opening in the formation.
 4734. The system of claim 4730, wherein the magnetic string is positionable within a first opening in the formation and wherein the magnetic string induces a magnetic field in a portion of the first opening.
 4735. The system of claim 4730, further comprising at least one heating mechanism within a first opening.
 4736. The system of claim 4730, further comprising at least one heating mechanism within a first opening and at least one heating mechanism within a second opening such that the heating mechanisms can provide heat to at least a portion of the formation.
 4737. The system of claim 4730, further comprising providing a series of magnetic fields along a portion of a first opening.
 4738. The system of claim 4730, wherein a length of a segment corresponds to a distance between the first opening and the second opening.
 4739. The system of claim 4730, wherein the magnetic string is movable in a first opening.
 4740. The system of claim 4730, wherein a position of the magnetic string in the first opening can be adjusted to increase a length of a second opening.
 4741. The system of claim 4730, further comprising a first opening positioned in the formation and wherein the magnetic string is positionable in the first opening.
 4742. The system of claim 4730, further comprising a non-metallic casing.
 4743. The system of claim 4730, wherein the magnetic segments comprises a first magnetic segment and a second magnetic, segment and wherein a length of the first magnetic segment differs from a length of the second magnetic segment.
 4744. The system of claim 4730, wherein the magnetic segments comprises a first magnetic segment and a second magnetic segment and wherein a length of the first magnetic segment is about the same as a length of the second magnetic segment.
 4745. The system of claim 4730, further comprising a casing and wherein the magnetic string is positioned within the casing.
 4746. A method of installing a conductor-in-conduit heat source of a desired length in a relatively permeable formation, comprising: assembling a conductor-in-conduit heat source of a desired length, comprising: placing a conductor within a conduit to form a conductor-in-conduit heat source; and coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source to form a conductor-in-conduit heat source of the desired length, wherein the conductor is electrically coupled to the conductor of at least one additional conductor-in-conduit heat source and the conduit is electrically coupled to the conduit of at least one additional conductor-in-conduit heat source; coiling the conductor-in-conduit heat source of the desired length after forming the heat source; and placing the conductor-in-conduit heat source of the desired length in an opening in a relatively permeable formation.
 4747. The method of claim 4746, wherein the conductor-in-conduit heat source is configurable to provide heat to the relatively permeable formation.
 4748. The method of claim 4746, wherein the conductor-in-conduit heat source of the desired length is removable from the opening in the relatively permeable formation.
 4749. The method of claim 4746, further comprising uncoiling the conductor-in-conduit heat source of the desired length while placing the heat source in the opening.
 4750. The method of claim 4746, further comprising placing at least one centralizer on the conductor.
 4751. The method of claim 4746, further comprising placing at least one centralizer on the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit.
 4752. The method of claim 4746, further comprising placing an insulation layer on at least a portion of the conductor.
 4753. The method of claim 4746, further comprising coiling the conductor-in-conduit heat source.
 4754. The method of claim 4746, further comprising testing the conductor-in-conduit heat source and coiling the heat source.
 4755. The method of claim 4746, wherein coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source comprises welding the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source.
 4756. The method of claim 4746, wherein coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source comprises shielded active gas welding the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source.
 4757. The method of claim 4746, wherein coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source comprises shielded active gas welding the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source, and wherein using shielded active gas welding inhibits changes in the grain structure of the conductor or conduit during coupling.
 4758. The method of claim 4746, wherein the assembling of the conductor-in-conduit heat source of the desired length is performed at a location proximate the relatively permeable formation.
 4759. The method of claim 4746, wherein the assembling of the conductor-in-conduit heat source of the desired length takes place sufficiently proximate the relatively permeable formation such that the conductor-in-conduit heat source can be placed directly in an opening of the formation after the heat source is assembled.
 4760. The method of claim 4746, further comprising coupling at least one substantially low resistance conductor to the conductor-in-conduit heat source of the desired length, wherein at least one substantially low resistance conductor is configured to be placed in an overburden of the formation.
 4761. The method of claim 4760, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.
 4762. The method of claim 4760, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises coupling a threaded end of at least one additional substantially low resistance conductor to a threaded end of at least one substantially low resistance conductor.
 4763. The method of claim 4760, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises welding at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.
 4764. The method of claim 4760, wherein at least one substantially low resistance conductor is coupled to the conductor-in-conduit heat source of the desired length during assembling of the heat source of the desired length.
 4765. The method of claim 4760, wherein at least one substantially low resistance conductor is coupled to the conductor-in-conduit heat source of the desired length after assembling of the heat source of the desired length.
 4766. The method of claim 4746, further comprising transporting the coiled conductor-in-conduit heat source of the desired length on a cart or train from an assembly location to the opening in the relatively permeable formation.
 4767. The method of claim 4766, wherein the cart or train can be further used to transport more than one conductor-in-conduit heat source of the desired length to more than one opening in the relatively permeable formation.
 4768. The method of claim 4746, wherein the desired length comprises a length determined for using the conductor-in-conduit heat source in a selected opening in the relatively permeable formation.
 4769. The method of claim 4746, further comprising treating the conductor to increase an emissivity of the conductor.
 4770. The method of claim 4769, wherein treating the conductor comprises roughening the surface of the conductor.
 4771. The method of claim 4769, wherein treating the conductor comprises heating the conductor to a temperature above about 750° C. in an oxidizing fluid atmosphere.
 4772. The method of claim 4746, further comprising treating the conduit to increase an emissivity of the conduit.
 4773. The method of claim 4746, further comprising coating at least a portion of the conductor or at least a portion of the conduit during assembly of the conductor-in-conduit heat source.
 4774. The method of claim 4746, further comprising placing an insulation layer on at least a portion of the conductor-in-conduit heat source prior to placing the heat source in the opening in the relatively permeable formation.
 4775. The method of claim 4774, wherein the insulation layer comprises a spiral insulation layer.
 4776. The method of claim 4774, wherein the insulation layer comprises at least one metal oxide.
 4777. The method of claim 4774, further comprising fastening at least a portion of the insulation layer to at least a portion of the conductor-in-conduit heat source with a high temperature glue.
 4778. The method of claim 4746, further comprising providing heat from the conductor-in-conduit heat source of the desired length to at least a portion of the formation.
 4779. The method of claim 4746, wherein a thickness of the conductor configurable to be placed adjacent to a lean zone in the formation is greater than a thickness of the conductor configurable to be placed adjacent to a rich zone in the formation such that more heat is provided to the rich zone during use.
 4780. The method of claim 4746, further comprising pyrolyzing at least some hydrocarbons in a selected section of the formation.
 4781. The method of claim 4746, further comprising producing a mixture from a selected section of the formation.
 4782. A method for making a conductor-in-conduit heat source configurable to be used to heat a relatively permeable formation, comprising: placing a conductor within a conduit to form a conductor-in-conduit heat source; and shielded active gas welding the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source to form a conductor-in-conduit heat source of a desired length, wherein the conductor is electrically coupled to the conductor of at least one additional conductor-in-conduit heat source and the conduit is electrically coupled to the conduit of at least one additional conductor-in-conduit heat source; and wherein the conductor-in-conduit heat source is configurable to be placed in an opening in the relatively permeable formation, and wherein the conductor-in-conduit heat source is further configurable to heat a section of the relatively permeable formation during use.
 4783. The method of claim 4782, further comprising providing heat from the conductor-in-conduit heat source of the desired length to at least a portion of the formation.
 4784. The method of claim 4782, further comprising pyrolyzing at least some hydrocarbons in a selected section of the formation.
 4785. The method of claim 4782, further comprising producing a mixture from a selected section of the formation.
 4786. The method of claim 4782, wherein the conductor and the conduit comprise stainless steel.
 4787. The method of claim 4782, wherein the conduit comprises stainless steel.
 4788. The method of claim 4782, wherein the heat source is configurable to be removed from the formation.
 4789. The method of claim 4782, further comprising providing a reducing gas during welding.
 4790. The method of claim 4782, wherein the reducing gas comprises molecular hydrogen.
 4791. The method of claim 4782, further comprising providing a reducing gas during welding such that welding occurs in an environment comprising less than about 25% reducing gas by volume.
 4792. The method of claim 4782, further comprising providing a reducing gas during welding such that welding occurs in an environment comprising about 10% reducing gas by volume.
 4793. A system configurable to heat a relatively permeable formation, comprising: a conduit configurable to be placed within an opening in the formation; a conductor configurable to be placed within the conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use, and wherein the conductor comprises at least two conductor sections coupled by shielded active gas welding; and wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use.
 4794. The system of claim 4793, wherein the conduit comprises at least two conduit sections coupled by shielded active gas welding.
 4795. The system of claim 4793, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.
 4796. The system of claim 4793, wherein the system is configured to heat a relatively permeable formation, and wherein the system comprises: a conduit configured to be placed within an opening in the formation; a conductor configured to be placed within the conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use, and wherein the conductor comprises at least two conductor sections coupled by shielded active gas welding; and wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.
 4797. The system of claim 4793, wherein the system heats a relatively permeable formation, and wherein the system comprises: a conduit placed within an opening in the formation; a conductor placed within the conduit, wherein the conductor provides heat to at least a portion of the formation during use, and wherein the conductor comprises at least two conductor sections coupled by shielded active gas welding; and wherein the system allows heat to transfer from the conductor to a section of the formation during use.
 4798. The system of claim 4793, wherein the conductor-in-conduit heat source is configurable to be removed from the formation.
 4799. A method for installing a heat source of a desired length in a relatively permeable formation, comprising: assembling a heat source of a desired length, wherein the assembling of the heat source of the desired length is performed at a location proximate the relatively permeable formation; coiling the heat source of the desired length after forming the heat source; and placing the heat source of the desired length in an opening in a relatively permeable formation, wherein placing the heat source in the opening comprises uncoiling the heat source while placing the heat source in the opening.
 4800. The method of claim 4799, wherein the heat source is configurable to heat a section of the relatively permeable formation.
 4801. The method of claim 4800, wherein the heat pyrolyzes at least some hydrocarbons in the section of the formation during use.
 4802. The method of claim 4799, further comprising coupling at least one substantially low resistance conductor to the heat source of the desired length, wherein at least one substantially low resistance conductor is configured to be placed in an overburden of the formation.
 4803. The method of claim 4802, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.
 4804. The method of claim 4802, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises coupling a threaded end of at least one additional substantially low resistance conductor to a threaded end of at least one substantially low resistance conductor.
 4805. The method of claim 4802, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises welding at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.
 4806. The method of claim 4799, further comprising transporting the heat source of the desired length on a cart or train from an assembly location to the opening in the relatively permeable formation.
 4807. The method of claim 4806, wherein the cart or train can be further used to transport more than one heat source to more than one opening in the relatively permeable formation.
 4808. The method of claim 4806, wherein the heat source is configurable to removable from the opening.
 4809. A method for installing a heat source of a desired length in a relatively permeable formation, comprising: assembling a heat source of a desired length, wherein the assembling of the heat source of the desired length is performed at a location proximate the relatively permeable formation; coiling the heat source of the desired length after forming the heat source; placing the heat source of the desired length in an opening in a relatively permeable formation, wherein placing the heat source in the opening comprises uncoiling the heat source while placing the heat source in the opening; and wherein the heat source is configurable to be removed from the opening.
 4810. The method of claim 4809, wherein the heat source is configurable to heat a section of the relatively permeable formation.
 4811. The method of claim 4810, wherein the heat pyrolyzes at least some hydrocarbons in the section of the formation during use.
 4812. The method of claim 4809, further comprising coupling at least one substantially low resistance conductor to the heat source of the desired length, wherein at least one substantially low resistance conductor is configured to be placed in an overburden of the formation.
 4813. The method of claim 4812, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.
 4814. The method of claim 4812, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises coupling a threaded end of at least one additional substantially low resistance conductor to a threaded end of at least one substantially low resistance conductor.
 4815. The method of claim 4812, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises welding at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.
 4816. The method of claim 4809, further comprising transporting the heat source of the desired length on a cart or train from an assembly location to the opening in the relatively permeable formation.
 4817. The method of claim 4809, wherein removing the heat source comprises recoiling the heat source.
 4818. The method of claim 4809, wherein the heat source can be removed from the opening and installed in an alternate opening in the formation.
 4819. A system configurable to heat a relatively permeable formation, comprising: a conduit configurable to be placed within an opening in the formation; a conductor configurable to be placed within a conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use; an electrically conductive material configurable to be coupled to at least a portion of the conductor, wherein the electrically conductive material is configurable to lower an electrical resistance of the conductor in the overburden during use; and wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use.
 4820. The system of claim 4819, further comprising an electrically conductive material configurable to be coupled to at least a portion of an inside surface of the conduit.
 4821. The system of claim 4819, further comprising a substantially low resistance conductor configurable to be electrically coupled to the conductor and the electrically conductive material during use, wherein the substantially low resistance conductor is further configurable to be placed within an overburden of the formation.
 4822. The system of claim 4821, wherein the low resistance conductor comprises carbon steel.
 4823. The system of claim 4819, wherein the electrically conductive material comprises metal tubing configurable to be clad to the conductor.
 4824. The system of claim 4819, wherein the electrically conductive material comprises an electrically conductive coating configurable to be applied to the conductor.
 4825. The system of claim 4819, wherein the electrically conductive material comprises a thermal plasma applied coating.
 4826. The system of claim 4819, wherein the electrically conductive material is configurable to be sprayed on the conductor.
 4827. The system of claim 4819, wherein the electrically conductive material comprises aluminum.
 4828. The system of claim 4819, wherein the electrically conductive material comprises copper.
 4829. The system of claim 4819, wherein the electrically conductive material is configurable to reduce the electrical resistance of the conductor in the overburden by a factor of greater than about
 3. 4830. The system of claim 4819, wherein the electrically conductive material is configurable to reduce the electrical resistance of the conductor in the overburden by a factor of greater than about
 15. 4831. The system of claim 4819, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.
 4832. The system of claim 4819, wherein the system is configured to heat a relatively permeable formation, and wherein the system comprises: a conduit configured to be placed within an opening in the formation; a conductor configured to be placed within a conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use; an electrically conductive material configured to be coupled to the conductor, wherein the electrically conductive material is further configured to lower an electrical resistance of the conductor in the overburden during use; and wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.
 4833. The system of claim 4819, wherein the system heats a relatively permeable formation, and wherein the system comprises: a conduit placed within an opening in the formation; a conductor placed within a conduit, wherein the conductor is provides heat to at least a portion of the formation during use; an electrically conductive material coupled to the conductor, wherein the electrically conductive material lowers an electrical resistance of the conductor in the overburden during use; and wherein the system allows heat to transfer from the conductor to a section of the formation during use.
 4834. An in situ method for heating a relatively permeable formation, comprising: applying an electrical current to a conductor to provide heat to at least a portion of the formation, wherein the conductor is placed in a conduit, and wherein the conduit is placed in an opening in the formation, and wherein the conductor is coupled to an electrically conductive material; and allowing the heat to transfer from the conductor to a section of the formation.
 4835. The method of claim 4834, wherein the electrically conductive material comprises copper.
 4836. The method of claim 4834, further comprising coupling an electrically conductive material to an inside surface of the conduit.
 4837. The method of claim 4834, wherein the electrically conductive material comprises metal tubing clad to the substantially low resistance conductor.
 4838. The method of claim 4834, wherein the electrically conductive material reduces an electrical resistance of the substantially low resistance conductor in the overburden.
 4839. The method of claim 4834, further comprising pyrolyzing at least some hydrocarbons within the formation.
 4840. A system configurable to heat a relatively permeable formation, comprising: a conduit configurable to be placed within an opening in the formation; a conductor configurable to be placed within a conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor; and wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use.
 4841. The system of claim 4840, wherein at least a portion of the surface of the conductor has been roughened to increase the emissivity of the conductor.
 4842. The system of claim 4840, wherein the conductor has been heated to a temperature above about 750° C. in an oxidizing fluid atmosphere to increase the emissivity of at least a portion of the surface of the conductor.
 4843. The system of claim 4840, wherein the conduit has been treated to increase an emissivity of at least a portion of the surface of the conduit.
 4844. The system of claim 4840, further comprising an electrically insulative, thermally conductive coating coupled to the conductor.
 4845. The system of claim 4844, wherein the electrically insulative, thermally conductive coating is configurable to electrically insulate the conductor from the conduit.
 4846. The system of claim 4844, wherein the electrically insulative, thermally conductive coating inhibits emissivity of the conductor from decreasing.
 4847. The system of claim 4844, wherein the electrically insulative, thermally conductive coating substantially increases an emissivity of the conductor.
 4848. The system of claim 4844, wherein the electrically insulative, thermally conductive coating comprises silicon oxide.
 4849. The system of claim 4844, wherein the electrically insulative, thermally conductive coating comprises aluminum oxide.
 4850. The system of claim 4844, wherein the electrically insulative, thermally conductive coating comprises refractive cement.
 4851. The system of claim 4844, wherein the electrically insulative, thermally conductive coating is sprayed on the conductor.
 4852. The system of claim 4840, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.
 4853. The system of claim 4840, wherein the system is configured to heat a relatively permeable formation, and wherein the system comprises: a conduit configured to be placed within an opening in the formation; a conductor configured to be placed within a conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor; and wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.
 4854. The system of claim 4840, wherein the system heats a relatively permeable formation, and wherein the system comprises: a conduit placed within an opening in the formation; a conductor placed within a conduit, wherein the conductor provides heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor; and wherein the system allows heat to transfer from the conductor to a section of the formation during use.
 4855. A heat source configurable to heat a relatively permeable formation, comprising: a conduit configurable to be placed within an opening in the formation; and a conductor configurable to be placed within a conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor.
 4856. The heat source of claim 4855, wherein at least a portion of the surface of the conductor has been roughened to increase the emissivity the conductor.
 4857. The heat source of claim 4855, wherein the conductor has been heated to a temperature above about 750° C. in an oxidizing fluid atmosphere to increase the emissivity of at least at least a portion of the surface of the conductor.
 4858. The heat source of claim 4855, wherein the conduit has been treated to increase an emissivity of at least a portion of the surface of the conduit.
 4859. The heat source of claim 4855, further comprising an electrically insulative, thermally conductive coating placed on the conductor.
 4860. The heat source of claim 4859, wherein the electrically insulative, thermally conductive coating is configurable to electrically insulate the conductor from the conduit.
 4861. The heat source of claim 4859, wherein the electrically insulative, thermally conductive coating substantially maintains an emissivity of the conductor.
 4862. The heat source of claim 4859, wherein the electrically insulative, thermally conductive coating substantially increases an emissivity of the conductor.
 4863. The heat source of claim 4859, wherein the electrically insulative, thermally conductive coating comprises silicon oxide.
 4864. The heat source of claim 4859, wherein the electrically insulative, thermally conductive coating comprises aluminum oxide.
 4865. The heat source of claim 4859, wherein the electrically insulative, thermally conductive coating comprises refractive cement.
 4866. The heat source of claim 4859, wherein the electrically insulative, thermally conductive coating is sprayed on the conductor.
 4867. The heat source of claim 4855, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use such that at least some hydrocarbons pyrolyze in the heated section of the formation during use.
 4868. The heat source of claim 4855, wherein the heat source is configured to heat a relatively permeable formation, and wherein the system comprises: a conduit configured to be placed within an opening in the formation; a conductor configured to be placed within a conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor.
 4869. The heat source of claim 4855, wherein the heat source heats a relatively permeable formation, and wherein the system comprises: a conduit placed within an opening in the formation; a conductor placed within a conduit, wherein the conductor provides heat to at least a portion of the formation, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor.
 4870. A method for forming an increased emissivity conductor-in-conduit heat source, comprising: treating a surface of a conductor to increase an emissivity of at least the surface of the conductor; placing the conductor within a conduit to form a conductor-in-conduit heat source; and wherein the conductor-in-conduit heat source is configurable to heat a relatively permeable formation.
 4871. The method of claim 4870, wherein treating the surface of the conductor comprises roughening at least a portion of the surface of the conductor.
 4872. The method of claim 4870, wherein treating the surface of the conductor comprises heating the conductor to a temperature above about 750° C. in an oxidizing fluid atmosphere.
 4873. The method of claim 4870, further comprising treating a surface of the conduit to increase an emissivity of at least a portion of the surface of the conduit.
 4874. The method of claim 4870, further comprising placing the conductor-in-conduit heat source of the desired length in an opening in a relatively permeable formation.
 4875. The method of claim 4870, further comprising assembling a conductor-in-conduit heat source of a desired length, the assembling comprising: coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source to form a conductor-in-conduit heat source of a desired length, wherein the conductor is electrically coupled to the conductor of at least one additional conductor-in-conduit heat source and the conduit is electrically coupled to the conduit of at least one additional conductor-in-conduit heat source; coiling the conductor-in-conduit heat source of the desired length after forming the heat source; and placing the conductor-in-conduit heat source of the desired length in an opening in a relatively permeable formation.
 4876. The method of claim 4870, wherein the conductor-in-conduit heat source is configurable to heat to a section of the relatively permeable formation, and wherein the heat pyrolyzes at least some hydrocarbons in the section of the formation during use.
 4877. A system configurable to heat a relatively permeable formation, comprising: a heat source configurable to be placed in an opening in the formation, wherein the heat source is further configurable to provide heat to at least a portion of the formation during use; an expansion mechanism configurable to be coupled to the heat source, wherein the expansion mechanism is configurable to allow for movement of the heat source during use; and wherein the system is configurable to allow heat to transfer to a section of the formation during use.
 4878. The system of claim 4877, wherein the expansion mechanism is configurable to allow for expansion of the heat source during use.
 4879. The system of claim 4877, wherein the expansion mechanism is configurable to allow for contraction of the heat source during use.
 4880. The system of claim 4877, wherein the expansion mechanism is configurable to allow for expansion of at least one component of the heat source during use.
 4881. The system of claim 4877, wherein the expansion mechanism is configurable to allow for expansion and contraction of the heat source within a wellbore during use.
 4882. The system of claim 4877, wherein the expansion mechanism comprises spring loading.
 4883. The system of claim 4877, wherein the expansion mechanism comprises an accordion mechanism.
 4884. The system of claim 4877, wherein the expansion mechanism is configurable to be coupled to a bottom of the heat source.
 4885. The system of claim 4877, wherein the heat source is configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.
 4886. The system of claim 4877, wherein the system is configured to heat a relatively permeable formation, and wherein the system comprises: a heat source configured to be placed in an opening in the formation, wherein the heat source is further configured to provide heat to at least a portion of the formation during use; an expansion mechanism configured to be coupled to the heat source, wherein the expansion mechanism is configured to allow for movement of the heat source during use; and wherein the system is configured to allow heat to transfer to a section of the formation during use.
 4887. The system of claim 4877, wherein the system heats a relatively permeable formation, and wherein the system comprises: a heat source placed in an opening in the formation, wherein the heat source provides heat to at least a portion of the formation during use; an expansion mechanism coupled to the heat source, wherein the expansion mechanism allows for movement of the heat source during use; and wherein the system allows heat to transfer to a section of the formation during use.
 4888. The system of claim 4877, wherein the heat source is removable.
 4889. A system configurable to provide heat to a relatively permeable formation, comprising: a conduit positionable in at least a portion of an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and an oxidizer configurable to provide heat to a selected section of the formation by transferring heat through the conduit.
 4890. The system of claim 4889, wherein heat from the oxidizer pyrolyzes at least some hydrocarbons in the selected section.
 4891. The system of claim 4889, wherein the conduit is positioned in the opening.
 4892. The system of claim 4889, wherein the oxidizer is positionable in the conduit.
 4893. The system of claim 4889, wherein the oxidizer is positioned in the conduit, and wherein the oxidizer is configured to heat the selected section.
 4894. The system of claim 4889, wherein the oxidizer comprises a ring burner.
 4895. The system of claim 4889, wherein the oxidizer comprises an inline burner.
 4896. The system of claim 4889, wherein the oxidizer is configurable to provide heat in the conduit.
 4897. The system of claim 4889, further comprising an annulus formed between a wall of the conduit and a wall of the opening.
 4898. The system of claim 4889, wherein the oxidizer comprises a first oxidizer and a second oxidizer, and further comprising an annulus formed between a wall of the conduit and a wall of the opening, wherein the second oxidizer is positionable in the annulus.
 4899. The system of claim 4898, wherein the first oxidizer is configurable to provide heat in the conduit, and wherein the second oxidizer is configurable to provide heat outside of the conduit.
 4900. The system of claim 4898, wherein heat provided by the first oxidizer transfers in the first conduit in a direction opposite of heat provided by the second oxidizer.
 4901. The system of claim 4898, wherein heat provided by the first oxidizer transfers in the first conduit in a same direction as heat provided by the second oxidizer.
 4902. The system of claim 4889, wherein the oxidizer is configurable to oxidize fuel to generate heat, and further comprising a recycle conduit configurable to recycle at least some of the fuel in the conduit to a fuel source.
 4903. The system of claim 4889, wherein the oxidizer comprises a first oxidizer positioned in the conduit and a second oxidizer positioned in an annulus formed between a wall of the conduit and a wall of the opening, wherein the oxidizers are configurable to oxidize fuel to generate heat, and further comprising: a first recycle conduit configurable to recycle at least some of the fuel in the conduit to the second oxidizer; and a second recycle conduit configurable to recycle at least some of the fuel in the annulus to the first oxidizer.
 4904. The system of claim 4889, further comprising insulation positionable proximate the oxidizer.
 4905. An in situ method for heating a relatively permeable formation, comprising: providing heat to a conduit positioned in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and allowing the heat in the conduit to transfer through the opening and to a surrounding portion of the formation.
 4906. The method of claim 4905, further comprising: providing fuel to an oxidizer; oxidizing at least some of the fuel; and allowing oxidation products to migrate through the opening, wherein the oxidation products comprise heat.
 4907. The method of claim 4906, wherein the fuel is provided to the oxidizer proximate the first location, and wherein the oxidation products migrate towards the second location.
 4908. The method of claim 4905, wherein the oxidizer comprises a ring burner.
 4909. The method of claim 4905, wherein the oxidizer comprises an inline burner.
 4910. The method of claim 4905, further comprising recycling at least some fuel in the conduit.
 4911. A system configurable to provide heat to a relatively permeable formation, comprising: a conduit positionable in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, wherein a second end of the opening contacts the earth surface at a second location; an annulus formed between a wall of the conduit and a wall of the opening; and a oxidizer configurable to provide heat to a selected section of the formation by transferring heat through the annulus.
 4912. The system of claim 4911, wherein heat from the oxidizer pyrolyzes at least some hydrocarbons in the selected section.
 4913. The system of claim 4911, wherein the conduit is positioned in the opening.
 4914. The system of claim 4911, wherein the oxidizer comprises a first oxidizer and a second oxidizer, wherein the second oxidizer is positioned in the conduit, and wherein the second oxidizer is configured to heat the selected section.
 4915. The system of claim 4911, wherein the oxidizer comprises a ring burner.
 4916. The system of claim 4911, wherein the oxidizer comprises an inline burner.
 4917. The system of claim 4914, wherein heat provided by the first oxidizer transfers in the first conduit in a direction opposite of heat provided by the second oxidizer.
 4918. The system of claim 4911, wherein the oxidizer is configurable to oxidize fuel to generate heat, and further comprising a recycle conduit configurable to recycle at least some of the fuel in the conduit to a fuel source.
 4919. The system of claim 4911, further comprising insulation positionable proximate the oxidizer.
 4920. The system of claim 4911, wherein the conduit is positioned in the opening.
 4921. The system of claim 4911, wherein the oxidizer is positioned in the annulus, and wherein the oxidizer is configured to heat the selected section.
 4922. The system of claim 4911, wherein the oxidizer comprises a first oxidizer and a second oxidizer.
 4923. The system of claim 4922, wherein heat provided by the first oxidizer transfers through the opening in a direction opposite of heat provided by the second oxidizer.
 4924. The system of claim 4911, wherein the oxidizer is configurable to oxidize fuel to generate heat, and further comprising a recycle conduit configurable to recycle at least some of the fuel in the annulus to a fuel source.
 4925. The system of claim 491, further comprising insulation positionable proximate the oxidizer.
 4926. The system of claim 4922, wherein the first oxidizer and the second oxidizer comprise oxidizers, and wherein a first mixture of oxidation products generated by the first oxidizer flows countercurrent to a second mixture of oxidation products generated by the second heater.
 4927. The system of claim 4922, wherein the first heater and the second heater comprise oxidizers, wherein fuel is oxidized by the oxidizers to generate heat, and further comprising a first recycle conduit to recycle fuel in the first conduit proximate the second location to the second conduit.
 4928. The system of claim 4922, wherein the first oxidizer and the second oxidizer comprise oxidizers, wherein fuel is oxidized by the oxidizers to generate heat, and further comprising a second recycle conduit to recycle fuel in the second conduit proximate the first location to the first conduit.
 4929. The system of claim 4911, further comprising a casing, wherein the conduit is positionable in the casing.
 4930. The system of claim 4911, wherein the oxidizer comprises a first oxidizer positioned in the annulus and a second oxidizer positioned in the conduit, wherein the oxidizers are configurable to oxidize fuel to generate heat, and further comprising: a first recycle conduit configurable to recycle at least some of the fuel in the annulus to the second oxidizer; and a second recycle conduit configurable to recycle at least some of the fuel in the conduit to the first oxidizer.
 4931. An in situ method for heating a relatively permeable formation, comprising: providing heat to an annulus formed between a wall of an opening in the formation and a wall of a conduit in the opening, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and allowing the heat in the annulus to transfer through the opening and to a surrounding portion of the formation.
 4932. The method of claim 4931, further comprising: providing fuel to an oxidizer; oxidizing at least some of the fuel; and allowing oxidation products to migrate through the opening, wherein the oxidation products comprise heat.
 4933. The method of claim 4932, wherein the fuel is provided the oxidizer proximate the first location, and wherein the oxidation products migrate towards the second location.
 4934. The method of claim 4931, wherein the oxidizer comprises a ring burner.
 4935. The method of claim 4931, wherein the oxidizer comprises an inline burner.
 4936. The method of claim 4931, further comprising recycling at least some fuel in the conduit.
 4937. A system configurable to provide heat to a relatively permeable formation, comprising: a first conduit positionable in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, wherein a second end of the opening contacts the earth surface at a second location; a second conduit positionable in the opening; a first oxidizer configurable to provide heat to a selected section of the formation by transferring heat through the first conduit; and a second oxidizer configurable to provide heat to the selected section of the formation by transferring heat through the second conduit.
 4938. The system of claim 4937, wherein the first oxidizer is positionable in the first conduit.
 4939. The system of claim 4937, wherein the second oxidizer is positionable in the second conduit.
 4940. The system of claim 4937, further comprising a casing positionable in the opening.
 4941. The system of claim 4937, wherein at least a portion of the second conduit is positionable in the first conduit, and further comprising an annulus formed between a wall of the first conduit and a wall of the second conduit.
 4942. The system of claim 4937, wherein a portion of the second conduit is positionable proximate a portion of the first conduit.
 4943. The system of claim 4937, wherein the first oxidizer or the second oxidizer provide heat to at least a portion of the formation.
 4944. The system of claim 4937, wherein the first oxidizer and the second oxidizer provide heat to at least a portion of the formation concurrently.
 4945. The system of claim 4937, wherein the first oxidizer is positioned in the first conduit, wherein the second oxidizer is positioned in the second conduit, wherein the first oxidizer and the second oxidizer comprise oxidizers, and wherein a first flow of oxidation products from the first oxidizer flows in a direction opposite of a second flow of oxidation products from the second oxidizer.
 4946. The system of claim 4937, further comprising: a first recycle conduit configurable to recycle at least some of the fuel in the first conduit to the second oxidizer; and a second recycle conduit configurable to recycle at least some of the fuel in the second conduit to the first oxidizer.
 4947. An in situ method for heating a relatively permeable formation, comprising: providing heat to a first conduit positioned in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; providing heat to a second conduit positioned in the opening in the formation; allowing the heat in the first conduit to transfer through the opening and to a surrounding portion of the formation; and allowing the heat in the second conduit to transfer through the opening and to a surrounding portion of the formation.
 4948. The method of claim 4947, wherein providing heat to the first conduit comprises providing fuel to an oxidizer.
 4949. The method of claim 4947, wherein providing heat to the second conduit comprises providing fuel to an oxidizer.
 4950. The method of claim 4947, wherein the first fuel is provided to the first conduit proximate the first location, and wherein the second fuel is provided to the second conduit proximate the second location.
 4951. The method of claim 4947, wherein the first oxidizer or the second oxidizer comprises a ring burner.
 4952. The method of claim 4947, wherein the first oxidizer or the second oxidizer an inline burner.
 4953. The method of claim 4947, further comprising: transferring heat through the first conduit in a first direction; and transferring heat in the second conduit in a second direction.
 4954. The method of claim 4947, further comprising recycling at least some fuel in the first conduit to the second conduit; and recycling at least some fuel in the second conduit to the first conduit.
 4955. A system configurable to provide heat to a relatively permeable formation, comprising: a first conduit positionable in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, wherein a second end of the opening contacts the earth surface at a second location; a second conduit positionable in the first conduit; and at least one surface unit configurable to provide heat to the first conduit.
 4956. The system of claim 4955, wherein the surface unit comprises a furnace.
 4957. The system of claim 4955, wherein the surface unit comprises a burner.
 4958. The system of claim 4955, wherein at least one surface unit is configurable to provide heat to the second conduit.
 4959. The system of claim 4958, wherein the first conduit and the second conduit provide heat to at least a portion of the formation.
 4960. The system of claim 4958, wherein the first conduit provides heat to at least a portion of the formation.
 4961. The system of claim 4958, wherein the second conduit provides heat to at least a portion of the formation.
 4962. The system of claim 4955, further comprising a casing positionable in the opening.
 4963. The method of claim 4955, wherein the first conduit and the second conduit are concentric.
 4964. An in situ method for heating a relatively permeable formation, comprising: heating a fluid using at least one surface unit; providing the heated fluid to a first conduit wherein a portion of the first conduit is positioned in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; allowing the heated fluid to flow into a second conduit, wherein the first conduit is positioned within the second conduit; and allowing heat from the first and second conduit to transfer to a portion of the formation.
 4965. The method of claim 4964, further comprising providing additional heat to the heated fluid using at least one surface unit proximate the second location.
 4966. The method of claim 4964, wherein the fluid comprises an oxidizing fluid.
 4967. The method of claim 4964, wherein the fluid comprises air.
 4968. The method of claim 4964, wherein the fluid comprises flue gas.
 4969. The method of claim 4964, wherein the fluid comprises steam.
 4970. The method of claim 4964, wherein the fluid comprises fuel.
 4971. The method of claim 4964, further comprising compressing the fluid prior to heating.
 4972. The method of claim 4964, wherein the surface unit comprises a furnace.
 4973. The method of claim 4964, wherein the surface unit comprises an indirect furnace.
 4974. The method of claim 4964, wherein the surface unit comprises a burner.
 4975. The method of claim 4964, wherein the first conduit and the second conduit are concentric.
 4976. A system configurable to provide heat to a relatively permeable formation, comprising: a conduit positionable in at least a portion of an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and at least two oxidizers configurable to provide heat to a portion of the formation.
 4977. The system of claim 4976, wherein heat from the oxidizers pyrolyzes at least some hydrocarbons in the selected section.
 4978. The system of claim 4976, wherein the conduit comprises a fuel conduit.
 4979. The system of claim 4976, wherein at least one oxidizer is positionable proximate the conduit.
 4980. The system of claim 4976, wherein at least one oxidizer comprises a ring burner.
 4981. The system of claim 4976, wherein at least one oxidizer comprises an inline burner.
 4982. The system of claim 4976, further comprising insulation positionable proximate at least one oxidizer.
 4983. The system of claim 4976, further comprising a casing comprising insulation proximate at least one oxidizer.
 4984. An in situ method for heating a relatively permeable formation, comprising: providing fuel to a conduit positioned in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; providing an oxidizing fluid to the opening; oxidizing fuel in at least one oxidizer positioned proximate the conduit; and allowing heat to transfer to a portion of the formation.
 4985. The method of claim 4984, further comprising providing steam to the conduit.
 4986. The method of claim 4984, further comprising inhibiting coking within the conduit.
 4987. The method of claim 4984, wherein the oxidizing fluid comprises air.
 4988. The method of claim 4984, wherein the oxidizing fluid comprises oxygen.
 4989. The method of claim 4984, further comprising allowing oxidation products to exit the opening proximate the second location.
 4990. The method of claim 4984, wherein the fuel is provided to proximate the first location, and wherein the oxidation products migrate towards the second location.
 4991. The method of claim 4984, wherein the oxidizer comprises a ring burner.
 4992. The method of claim 4984, wherein the oxidizer comprises an inline burner.
 4993. The method of claim 4984, further comprising recycling at least some fuel in the conduit.
 4994. The method of claim 4984, wherein the opening comprises a casing and further comprising insulating a portion of the casing proximate at least one oxidizer.
 4995. The method of claim 4984, further comprising at least two oxidizers, wherein the oxidizers are positioned about 30 m apart.
 4996. A system configurable to provide heat to a relatively permeable formation, comprising: a conduit positionable in at least a portion of an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and an oxidizing fluid source configurable to provide an oxidizing fluid to a reaction zone of the formation.
 4997. The system of claim 4996, wherein the conduit comprises a conductor and wherein the conductor is configured to generate heat during application of an electrical current to the conduit.
 4998. The system of claim 4996, wherein the conduit comprises a low resistance conductor and wherein at least some of the low resistance conductor is positionable in an overburden.
 4999. The system of claim 4996, wherein the oxidizing fluid source is configurable to provide at least some oxidizing fluid to the conduit at the first location and at the second location.
 5000. The system of claim 4996, wherein the opening is configurable to allow products of oxidation to be produced from the formation.
 5001. The system of claim 4996, wherein the oxidizing fluid reacts with at least some hydrocarbons and wherein the oxidizing fluid source is configurable to provide at least some oxidizing fluid to the first location and to the second location.
 5002. The system of claim 4996, wherein the heat source is configurable to heat a reaction zone of the selected section to a temperature sufficient to support reaction of hydrocarbons in the selected section with an oxidizing fluid.
 5003. The system of claim 5002, wherein the heat source is configurable to provide an oxidizing fluid to the selected section of the formation to generate heat during use.
 5004. The system of claim 5002, wherein the generated heat transfers to a pyrolysis zone of the formation.
 5005. The system of claim 4996, further comprising an oxidizing fluid source configurable to provide an oxidizing fluid to the heat source, and wherein the conduit is configurable to provide the oxidizing fluid to the selected section of the formation during use.
 5006. The system of claim 4996, wherein the conduit comprises a low resistance conductor and a conductor, and wherein the conductor is further configured to generate heat during application of an electrical current to the conduit.
 5007. An in situ method for heating a relatively permeable formation, comprising: providing an electrical current to a conduit positioned in an opening in the formation; allowing heat to transfer from the conduit to a reaction zone of the formation; providing at least some oxidizing fluid to the conduit; allowing the oxidizing fluid to transfer from the conduit to the reaction zone in the formation; allowing the oxidizing fluid to oxidize at least some hydrocarbons in the reaction zone to generate heat; and allowing at least some of the generated heat to transfer to a pyrolysis zone in the formation.
 5008. The method of claim 5007, wherein at least a portion of the conduit is configured to generate heat during application of the electrical current to the conduit.
 5009. The method of claim 5007, further comprising: providing at least some oxidizing fluid to the conduit proximate a first end of the conduit; providing at least some oxidizing fluid to the conduit proximate a second end of the conduit; and wherein the first end of the conduit is positioned at a first location on a surface of the formation and wherein the second end of the conduit is positioned at a second location on the surface.
 5010. The method of claim 5007, further comprising allowing the oxidizing fluid to move out of the conduit through orifices positioned on the conduit.
 5011. The method of claim 5007, further comprising removing products of oxidation through the opening during use.
 5012. The method of claim 5007, wherein a first end of the opening is positioned at a first location on a surface of the formation and wherein a second end of the opening is positioned at a second location on the surface.
 5013. The method of claim 5007, further comprising heating the reaction zone to a temperature sufficient to support reaction of hydrocarbons with an oxidizing fluid.
 5014. The method of claim 5007, further comprising controlling a flow rate of the oxidizing fluid into the formation.
 5015. The method of claim 5007, further comprising controlling a temperature in the pyrolysis zone.
 5016. The method of claim 5007, further comprising removing products from oxidation through an opening in the formation during use.
 5017. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a first section of the formation such that the heat from the one or more heat sources pyrolyzes at least some hydrocarbons within the first section; and producing a mixture through a second section of the formation, wherein the produced mixture comprises at least some pyrolyzed hydrocarbons from the first section, and wherein the second section comprises a higher permeability than the first section.
 5018. The method of claim 5017, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5019. The method of claim 5017, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5020. The method of claim 5017, wherein at least one heat source comprises a heater.
 5021. The method of claim 5017, further comprising increasing permeability within the second section by allowing heat to transfer from the one or more heat sources to the second section.
 5022. The method of claim 5017, wherein the second section has a higher permeability than the first section before providing heat to the formation.
 5023. The method of claim 5017, wherein the second section comprises an average permeability thickness product of greater than about 1100 millidarcy feet.
 5024. The method of claim 5017, wherein the first section comprises an initial average permeability thickness product of less than about 10 millidarcy feet.
 5025. The method of claim 5017, wherein the second section comprises an average permeability thickness product that is at least twice an initial average permeability thickness product of the first section.
 5026. The method of claim 5017, wherein the second section comprises an average permeability thickness product that is at least ten times an initial average permeability thickness product of the first section.
 5027. The method of claim 5017, wherein the one or more heat sources are placed within at least one uncased wellbore in the formation.
 5028. The method of claim 5027, further comprising allowing at least some hydrocarbons from the first section to propagate through at least one uncased wellbore into the second section.
 5029. The method of claim 5027, further comprising producing at least some hydrocarbons through at least one uncased wellbore.
 5030. The method of claim 5017, further comprising forming one or more fractures that propagate between the first section and the second section.
 5031. The method of claim 5030, further comprising allowing at least some hydrocarbons from the first section to propagate through the one or more fractures into the second section.
 5032. The method of claim 5017, further comprising producing the mixture from the formation through a production well placed in the second section.
 5033. The method of claim 5017, further comprising producing the mixture from the formation through a production well placed in the first section and the second section.
 5034. The method of claim 5017, further comprising inhibiting fracturing of a section of the formation that is substantially adjacent to an environmentally sensitive area.
 5035. The method of claim 5017, further comprising producing at least some hydrocarbons through the second section to maintain a pressure in the formation below a lithostatic pressure of the formation.
 5036. The method of claim 5017, further comprising producing at least some hydrocarbons through a production well placed in the first section.
 5037. The method of claim 5017, further comprising pyrolyzing at least some hydrocarbons within the second section.
 5038. The method of claim 5017, wherein the first section and the second section are substantially adjacent.
 5039. The method of claim 5017, further comprising allowing migration of fluids between the first second and the second section.
 5040. The method of claim 5017, wherein at least one heat source has a thickness of a conductor that is adjusted to provide more heat to the first section than the second section.
 5041. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation, wherein one or more of such heat sources is placed within at least one uncased wellbore in the formation; allowing the heat to transfer from the one or more heat sources to a first section of the formation such that the heat from the one or more heat sources pyrolyzes at least some hydrocarbons within the first section; and producing a mixture through a second section of the formation, wherein the produced mixture comprises at least some pyrolyzed hydrocarbons from the first section, and wherein the second section comprises a higher permeability than the first section.
 5042. The method of claim 5041, further comprising allowing at least some hydrocarbons from the first section to propagate through at least one uncased wellbore into the second section.
 5043. The method of claim 5041, further comprising producing at least some hydrocarbons through at least one uncased wellbore.
 5044. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: providing at least one property of the formation to the computer system; providing at least one operating condition of the process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and assessing at least one process characteristic of the in situ process using a simulation method on the computer system, and using at least one property of the formation and at least one operating condition.
 5045. The method of claim 5044, wherein at least one process characteristic is assessed as function of time.
 5046. The method of claim 5044, wherein the simulation method is a body-fitted finite difference simulation method.
 5047. The method of claim 5044, wherein the simulation method is a space-fitted finite difference simulation method.
 5048. The method of claim 5044, wherein the simulation method is a reservoir simulation method.
 5049. The method of claim 5044, wherein the simulation method simulates heat transfer by conduction.
 5050. The method of claim 5044, wherein the simulation method simulates heat transfer by convection.
 5051. The method of claim 5044, wherein the simulation method simulates heat transfer by radiation.
 5052. The method of claim 5044, wherein the simulation method simulates heat transfer in a near wellbore region.
 5053. The method of claim 5044, wherein the simulation method assesses a temperature distribution in the formation.
 5054. The method of claim 5044, wherein at least one property of the formation comprises one or more materials from the formation.
 5055. The method of claim 5054, wherein one material comprises mineral matter.
 5056. The method of claim 5054, wherein one material comprises organic matter.
 5057. The method of claim 5044, wherein at least one property of the formation comprises one or more phases.
 5058. The method of claim 5057, wherein one phase comprises a water phase.
 5059. The method of claim 5057, wherein one phase comprises an oil phase.
 5060. The method of claim 5059, wherein the oil phase comprises one or more components.
 5061. The method of claim 5057, wherein one phase comprises a gas phase.
 5062. The method of claim 5061, wherein the gas phase comprises one or more components.
 5063. The method of claim 5044, wherein at least one property of the formation comprises a porosity of the formation.
 5064. The method of claim 5044, wherein at least one property of the formation comprises a permeability of the formation.
 5065. The method of claim 5064, wherein the permeability depends on the composition of the formation.
 5066. The method of claim 5044, wherein at least one property of the formation comprises a saturation of the formation.
 5067. The method of claim 5044, wherein at least one property of the formation comprises a density of the formation.
 5068. The method of claim 5044, wherein at least one property of the formation comprises a thermal conductivity of the formation.
 5069. The method of claim 5044, wherein at least one property of the formation comprises a volumetric heat capacity of the formation.
 5070. The method of claim 5044, wherein at least one property of the formation comprises a compressibility of the formation.
 5071. The method of claim 5044, wherein at least one property of the formation comprises a composition of the formation.
 5072. The method of claim 5044, wherein at least one property of the formation comprises a thickness of the formation.
 5073. The method of claim 5044, wherein at least one property of the formation comprises a depth of the formation.
 5074. The method of claim 5044, wherein at least one property comprises one or more chemical components.
 5075. The method of claim 5074, wherein one component comprises a pseudo-component.
 5076. The method of claim 5044, wherein at least property comprises one or more kinetic parameters.
 5077. The method of claim 5044, wherein at least one property comprises one or more chemical reactions.
 5078. The method of claim 5077, wherein a rate of at least one chemical reaction depends on a pressure of the formation.
 5079. The method of claim 5077, wherein a rate of at least one chemical reaction depends on a temperature of the formation.
 5080. The method of claim 5077, wherein at least one chemical reaction comprises a pre-pyrolysis water generation reaction.
 5081. The method of claim 5077, wherein at least one chemical reaction comprises a hydrocarbon generating reaction.
 5082. The method of claim 5077, wherein at least one chemical reaction comprises a coking reaction.
 5083. The method of claim 5077, wherein at least one chemical reaction comprise a cracking reaction.
 5084. The method of claim 5077, wherein at least one chemical reaction comprises a synthesis gas reaction.
 5085. The method of claim 5044, wherein at least one process characteristic comprises an API gravity of produced fluids.
 5086. The method of claim 5044, wherein at least one process characteristic comprises an olefin content of produced fluids.
 5087. The method of claim 5044, wherein at least one process characteristic comprises a carbon number distribution of produced fluids.
 5088. The method of claim 5044, wherein at least one process characteristic comprises an ethene to ethane ratio of produced fluids.
 5089. The method of claim 5044, wherein at least one process characteristic comprises an atomic carbon to hydrogen ratio of produced fluids.
 5090. The method of claim 5044, wherein at least one process characteristic comprises a ratio of non-condensable hydrocarbons to condensable hydrocarbons of produced fluids.
 5091. The method of claim 5044, wherein at least one process characteristic comprises a pressure in the formation.
 5092. The method of claim 5044, wherein at least one process characteristic comprises total mass recovery from the formation.
 5093. The method of claim 5044, wherein at least one process characteristic comprises a production rate of fluid produced from the formation.
 5094. The method of claim 5044, wherein at least one operating condition comprises a pressure.
 5095. The method of claim 5044, wherein at least one operating condition comprises a temperature.
 5096. The method of claim 5044, wherein at least one operating condition comprises a heating rate.
 5097. The method of claim 5044, wherein at least one operating condition comprises a process time.
 5098. The method of claim 5044, wherein at least one operating condition comprises a location of producer wells.
 5099. The method of claim 5044, wherein at least one operating condition comprises an orientation of producer wells.
 5100. The method of claim 5044, wherein at least one operating condition comprises a ratio of producer wells to heater wells.
 5101. The method of claim 5044, wherein at least one operating condition comprises a spacing between heater wells.
 5102. The method of claim 5044, wherein at least one operating condition comprises a distance between an overburden and horizontal heater wells.
 5103. The method of claim 5044, wherein at least one operating condition comprises a pattern of heater wells.
 5104. The method of claim 5044, wherein at least one operating condition comprises an orientation of heater wells.
 5105. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: simulating a heat input rate to the formation from two or more heat sources on the computer system, wherein heat is allowed to transfer from the heat sources to a selected section of the formation; providing at least one desired parameter of the in situ process to the computer system; and controlling the heat input rate from the heat sources to achieve at least one desired parameter.
 5106. The method of claim 5105, wherein the heat is allowed to transfer from the heat sources substantially by conduction.
 5107. The method of claim 5105, wherein the heat input rate is simulated with a body-fitted finite difference simulation method.
 5108. The method of claim 5105, wherein simulating the heat input rate from two or more heat sources comprises simulating a model of one or more heat sources with symmetry boundary conditions.
 5109. The method of claim 5105, wherein superposition of heat from the two or more heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 5110. The method of claim 5105, wherein at least one desired parameter comprises a selected process characteristic.
 5111. The method of claim 5105, wherein at least one desired parameter comprises a selected temperature.
 5112. The method of claim 5105, wherein at least one desired parameter comprises a selected heating rate.
 5113. The method of claim 5105, wherein at least one desired parameter comprises a desired product mixture produced from the formation.
 5114. The method of claim 5105, wherein at least one desired parameter comprises a desired product mixture produced from the formation, and wherein the desired product mixture comprises a selected composition.
 5115. The method of claim 5105, wherein at least one desired parameter comprises a selected pressure.
 5116. The method of claim 5105, wherein at least one desired parameter comprises a selected heating time.
 5117. The method of claim 5105, wherein at least one desired parameter comprises a market parameter.
 5118. The method of claim 5105, wherein at least one desired parameter comprises a price of crude oil.
 5119. The method of claim 5105, wherein at least one desired parameter comprises an energy cost.
 5120. The method of claim 5105, wherein at least one desired parameter comprises a selected molecular hydrogen to carbon monoxide volume ratio.
 5121. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: providing at least one heat input property to the computer system; assessing heat injection rate data for the formation using a first simulation method on the computer system; providing at least one property of the formation to the computer system; assessing at least one process characteristic of the in situ process from the heat injection rate data and at least one property of the formation using a second simulation method; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5122. The method of claim 5121, wherein at least one process characteristic is assessed as a function of time.
 5123. The method of claim 5121, wherein assessing heat injection rate data comprises simulating heating of the formation.
 5124. The method of claim 5121, wherein the heating is controlled to obtain a desired parameter.
 5125. The method of claim 5121, wherein determining at least one process characteristic comprises simulating heating of the formation.
 5126. The method of claim 5125, wherein the heating is controlled to obtain a desired parameter.
 5127. The method of claim 5121, wherein the first simulation method is a body-fitted finite difference simulation method.
 5128. The method of claim 5121, wherein the second simulation method is a space-fitted finite difference simulation method.
 5129. The method of claim 5121, wherein the second simulation method is a reservoir simulation method.
 5130. The method of claim 5121, wherein the first simulation method simulates heat transfer by conduction.
 5131. The method of claim 5121, wherein the first simulation method simulates heat transfer by convection.
 5132. The method of claim 5121, wherein the first simulation method simulates heat transfer by radiation.
 5133. The method of claim 5121, wherein the second simulation method simulates heat transfer by conduction.
 5134. The method of claim 5121, wherein the second simulation method simulates heat transfer by convection.
 5135. The method of claim 5121 wherein the first simulation method simulates heat transfer in a near wellbore region.
 5136. The method of claim 5121, wherein the first simulation method determines a temperature distribution in the formation.
 5137. The method of claim 5121, wherein at least one heat input property comprises a property of the formation.
 5138. The method of claim 5121, wherein at least one heat input property comprises a heat transfer property.
 5139. The method of claim 5121, wherein at least one heat input property comprises an initial property of the formation.
 5140. The method of claim 5121, wherein at least one heat input property comprises a heat capacity.
 5141. The method of claim 5121, wherein at least one heat input property comprises a thermal conductivity.
 5142. The method of claim 5121, wherein the heat injection rate data comprises a temperature distribution within the formation.
 5143. The method of claim 5121, wherein the heat injection rate data comprises a heat input rate.
 5144. The method of claim 5143, wherein the heat input rate is controlled to maintain a specified maximum temperature at a point in the formation.
 5145. The method of claim 5121 wherein the heat injection rate data comprises heat flux data.
 5146. The method of claim 5121, wherein at least one property of the formation comprises one or more materials in the formation.
 5147. The method of claim 5146, wherein one material comprises mineral matter.
 5148. The method of claim 5146, wherein one material comprises organic matter.
 5149. The method of claim 5121, wherein at least one property of the formation comprises one or more phases.
 5150. The method of claim 5149, wherein one phase comprises a water phase.
 5151. The method of claim 5149, wherein one phase comprises an oil phase.
 5152. The method of claim 5151, wherein the oil phase comprises one or more components.
 5153. The method of claim 5149, wherein one phase comprises a gas phase.
 5154. The method of claim 5153, wherein the gas phase comprises one or more components.
 5155. The method of claim 5121, wherein at least one property of the formation comprises a porosity of the formation.
 5156. The method of claim 5121, wherein at least one property of the formation comprises a permeability of the formation.
 5157. The method of claim 5156, wherein the permeability depends on the composition of the formation.
 5158. The method of claim 5121, wherein at least one property of the formation comprises a saturation of the formation.
 5159. The method of claim 5121, wherein at least one property of the formation comprises a density of the formation.
 5160. The method of claim 5121, wherein at least one property of the formation comprises a thermal conductivity of the formation.
 5161. The method of claim 5121, wherein at least one property of the formation comprises a volumetric heat capacity of the formation.
 5162. The method of claim 5121, wherein at least one property of the formation comprises a compressibility of the formation.
 5163. The method of claim 5121, wherein at least one property of the formation comprises a composition of the formation.
 5164. The method of claim 5121, wherein at least one property of the formation comprises a thickness of the formation.
 5165. The method of claim 5121, wherein at least one property of the formation comprises a depth of the formation.
 5166. The method of claim 5121, wherein at least one property of the formation comprises one or more chemical components.
 5167. The method of claim 5166, wherein at least one chemical component comprises a pseudo-component.
 5168. The method of claim 5121, wherein at least one property of the formation comprises one or more kinetic parameters.
 5169. The method of claim 5121, wherein at least one property of the formation comprises one or more chemical reactions.
 5170. The method of claim 5169, wherein a rate of at least one chemical reaction depends on a pressure of the formation.
 5171. The method of claim 5169, wherein a rate of at least one chemical reaction depends on a temperature of the formation.
 5172. The method of claim 5169, wherein at least one chemical reaction comprises a pre-pyrolysis water generation reaction.
 5173. The method of claim 5169, wherein at least one chemical reaction comprises a hydrocarbon generating reaction.
 5174. The method of claim 5169, wherein at least one chemical reaction comprises a coking reaction.
 5175. The method of claim 5169, wherein at least one chemical reaction comprises a cracking reaction.
 5176. The method of claim 5169, wherein at least one chemical reaction comprises a synthesis gas reaction.
 5177. The method of claim 5121, wherein at least one process characteristic comprises an API gravity of produced fluids.
 5178. The method of claim 5121, wherein at least one process characteristic comprises an olefin content of produced fluids.
 5179. The method of claim 5121, wherein at least one process characteristic comprises a carbon number distribution of produced fluids.
 5180. The method of claim 5121, wherein at least one process characteristic comprises an ethene to ethane ratio of produced fluids.
 5181. The method of claim 5121, wherein at least one process characteristic comprises an atomic carbon to hydrogen ratio of produced fluids.
 5182. The method of claim 5121, wherein at least one process characteristic comprises a ratio of non-condensable hydrocarbons to condensable hydrocarbons of produced fluids.
 5183. The method of claim 5121, wherein at least one process characteristic comprises a pressure in the formation.
 5184. The method of claim 5121, wherein at least one process characteristic comprises a total mass recovery from the formation.
 5185. The method of claim 5121, wherein at least one process characteristic comprises a production rate of fluid produced from the formation.
 5186. The method of claim 5121, further comprising: assessing modified heat injection rate data using the first simulation method at a specified time of the second simulation method based on at least one heat input property of the formation at the specified time; assessing at least one process characteristic of the in situ process as a function of time from the modified heat injection rate data and at least one property of the formation at the specified time using the second simulation method.
 5187. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: providing one or more model parameters for the in situ process to the computer system; assessing one or more simulated process characteristics based on one or more model parameters using a simulation method; modifying one or more model parameters such that at least one simulated process characteristic matches or approximates at least one real process characteristic; assessing one or more modified simulated process characteristics based on the modified model parameters; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5188. The method of claim 5187, further comprising using the simulation method with the modified model parameters to determine at least one operating condition of the in situ process to achieve a desired parameter.
 5189. The method of claim 5187, wherein the simulation method comprises a body-fitted finite difference simulation method.
 5190. The method of claim 5187, wherein the simulation method comprises a space-fitted finite difference simulation method.
 5191. The method of claim 5187, wherein the simulation method comprises a reservoir simulation method.
 5192. The method of claim 5187, wherein the real process characteristics comprise process characteristics obtained from laboratory experiments of the in situ process.
 5193. The method of claim 5187, wherein the real process characteristics comprise process characteristics obtained from field test experiments of the in situ process.
 5194. The method of claim 5187, further comprising comparing the simulated process characteristics to the real process characteristics as a function of time.
 5195. The method of claim 5187, further comprising associating differences between the simulated process characteristics and the real process characteristics with one or more model parameters.
 5196. The method of claim 5187, wherein at least one model parameter comprises a chemical component.
 5197. The method of claim 5187, wherein at least one model parameter comprises a kinetic parameter.
 5198. The method of claim 5197, wherein the kinetic parameter comprises an order of a reaction.
 5199. The method of claim 5197, wherein the kinetic parameter comprises an activation energy.
 5200. The method of claim 5197, wherein the kinetic parameter comprises a reaction enthalpy.
 5201. The method of claim 5197, wherein the kinetic parameter comprises a frequency factor.
 5202. The method of claim 5187, wherein at least one model parameter comprises a chemical reaction.
 5203. The method of claim 5202, wherein at least one chemical reaction comprises a pre-pyrolysis water generation reaction.
 5204. The method of claim 5202, wherein at least one chemical reaction comprises a hydrocarbon generating reaction.
 5205. The method of claim 5202, wherein at least one chemical reaction comprises a coking reaction.
 5206. The method of claim 5202, wherein at least one chemical reaction comprises a cracking reaction.
 5207. The method of claim 5202, wherein at least one chemical reaction comprises a synthesis gas reaction.
 5208. The method of claim 5187, wherein one or more model parameters comprise one or more properties.
 5209. The method of claim 5187, wherein at least one model parameter comprises a relationship for the dependence of a property on a change in conditions in the formation.
 5210. The method of claim 5187, wherein at least one model parameter comprises an expression for the dependence of porosity on pressure in the formation.
 5211. The method of claim 5187, wherein at least one model parameter comprises an expression for the dependence of permeability on porosity.
 5212. The method of claim 5187, wherein at least one model parameter comprises an expression for the dependence of thermal conductivity on composition of the formation.
 5213. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: assessing at least one operating condition of the in situ process using a simulation method based on one or more model parameter; modifying at least one model parameter such that at least one simulated process characteristic of the in situ process matches or approximates at least one real process characteristic of the in situ process; assessing one or more modified simulated process characteristics based on the modified model parameters; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5214. The method of claim 5213, wherein at least one operating condition is assessed to achieve at least one desired parameter.
 5215. The method of claim 5213, wherein the real process characteristic comprises a process characteristic from a field test of the in situ process.
 5216. The method of claim 5213, wherein the simulation method comprises a body-fitted finite difference simulation method.
 5217. The method of claim 5213, wherein the simulation method comprises a space-fitted finite difference simulation method.
 5218. The method of claim 5213, wherein the simulation method comprises a reservoir simulation method.
 5219. A method of modeling a process of treating a relatively permeable formation in situ using a computer system, comprising: providing one or more model parameters to the computer system; assessing one or more first process characteristics based on the one or more model parameters using a first simulation method on the computer system; assessing one or more second process characteristics based on one or more model parameters using a second simulation method on the computer system; modifying one or more model parameters such that at least one first process characteristic matches or approximates at least one second process characteristic; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5220. The method of claim 5219, further comprising assessing one or more third process characteristics based on the one or more modified model parameters using the second simulation method.
 5221. The method of claim 5219, wherein modifying one or more model parameters such that at least one first process characteristic matches or approximates at least one second process characteristic further comprises: assessing at least one set of first process characteristics based on at least one set of modified model parameters using the first simulation method; and assessing the set of modified model parameters that results in at least one first process characteristic that matches or approximates at least one second process characteristic.
 5222. The method of claim 5219, wherein the first simulation method comprises a body-fitted finite difference simulation method.
 5223. The method of claim 5219, wherein the second simulation method comprises a space-fitted finite difference simulation method.
 5224. The method of claim 5219, wherein at least one first process characteristic comprises a process characteristic at a sharp interface in the formation.
 5225. The method of claim 5219, wherein at least one first process characteristic comprises a process characteristic at a combustion front in the formation.
 5226. The method of claim 5219, wherein modifying the one or more model parameters comprises changing the order of a chemical reaction.
 5227. The method of claim 5219, wherein modifying the one or more model parameters comprises adding one or more chemical reactions.
 5228. The method of claim 5219, wherein modifying the one or more model parameters comprises changing an activation energy.
 5229. The method of claim 5219, wherein modifying the one or more model parameters comprises changing a frequency factor.
 5230. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: providing to the computer system one or more values of at least one operating condition of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; assessing one or more values of at least one process characteristic corresponding to one or more values of at least one operating condition using a simulation method; providing a desired value of at least one process characteristic for the in situ process to the computer system; and assessing a desired value of at least one operating condition to achieve the desired value of at least one process characteristic from the assessed values of at least one process characteristic and the provided values of at least one operating condition.
 5231. The method of claim 5230, further comprising operating the in situ system using the desired value of at least one operating condition.
 5232. The method of claim 5230, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation.
 5233. The method of claim 5230, wherein the process comprises allowing heat to transfer from one or more heat sources to a selected section of the formation.
 5234. The method of claim 5230, wherein a value of at least one process characteristic comprises the process characteristic as a function of time.
 5235. The method of claim 5230, further comprising determining a value of at least one process characteristic based on the desired value of at least one operating condition using the simulation method.
 5236. The method of claim 5230, wherein determining the desired value of at least one operating condition comprises interpolating the desired value from the determined values of at least one process characteristic and the provided values of at least one operating condition.
 5237. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: providing a desired value of at least one process characteristic for the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and assessing a value of at least one operating condition to achieve the desired value of at least one process characteristic, wherein such assessing comprises using a relationship between at least one process characteristic and at least one operating condition for the in situ process, wherein such relationship is stored on a database accessible by the computer system.
 5238. The method of claim 5237, further comprising operating the in situ system using the desired value of at least one operating condition.
 5239. The method of claim 5237, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation.
 5240. The method of claim 5237, wherein the process comprises providing heat to transfer from one or more heat sources to a selected section of the formation.
 5241. The method of claim 5237, wherein the relationship is determined from one or more simulations of the in situ process using a simulation method.
 5242. The method of claim 5237, wherein the relationship comprises one or more values of at least one process characteristic and corresponding values of at least one operating condition.
 5243. The method of claim 5237, wherein the relationship comprises an analytical function.
 5244. The method of claim 5237, wherein determining the value of at least one operating condition comprises interpolating the value of at least one operating condition from the relationship.
 5245. The method of claim 5237, wherein at least one process characteristic comprises a selected composition of produced fluids.
 5246. The method of claim 5237, wherein at least one operating condition comprises a pressure.
 5247. The method of claim 5237, wherein at least one operating condition comprises a heat input rate.
 5248. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing at least one property of the formation to the computer system; providing at least one operating condition of the process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and assessing at least one process characteristic of the in situ process using a simulation method on the computer system, and using at least one property of the formation and at least one operating condition.
 5249. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing at least one property of the formation to the computer system; providing at least one operating condition of the process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and assessing at least one process characteristic of the in situ process using a simulation method on the computer system, and using at least one property of the formation and at least one operating condition.
 5250. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: simulating a heat input rate to the formation from two or more heat sources on the computer system, wherein heat is allowed to transfer from the heat sources to a selected section of the formation; providing at least one desired parameter of the in situ process to the computer system; and controlling the heat input rate from the heat sources to achieve at least one desired parameter.
 5251. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: simulating a heat input rate to the formation from two or more heat sources on the computer system, wherein heat is allowed to transfer from the heat sources to a selected section of the formation; providing at least one desired parameter of the in situ process to the computer system; and controlling the heat input rate from the heat sources to achieve at least one desired parameter.
 5252. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing at least one heat input property to the computer system; assessing heat injection rate data for the formation using a first simulation method on the computer system; providing at least one property of the formation to the computer system; assessing at least one process characteristic of the in situ process from the heat injection rate data and at least one property of the formation using a second simulation method; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5253. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing at least one heat input property to the computer system; assessing heat injection rate data for the formation using a first simulation method on the computer system; providing at least one property of the formation to the computer system; assessing at least one process characteristic of the in situ process from the heat injection rate data and at least one property of the formation using a second simulation method; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5254. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing one or more model parameters for the in situ process to the computer system; assessing one or more simulated process characteristics based on one or more model parameters using a simulation method; modifying one or more model parameters such that at least one simulated process characteristic matches or approximates at least one real process characteristic; assessing one or more modified simulated process characteristics based on the modified model parameters; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5255. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing one or more model parameters for the in situ process to the computer system; assessing one or more simulated process characteristics based on one or more model parameters using a simulation method; modifying one or more model parameters such that at least one simulated process characteristic matches or approximates at least one real process characteristic; assessing one or more modified simulated process characteristics based on the modified model parameters; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5256. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: assessing at least one operating condition of the in situ process using a simulation method based on one or more model parameter; modifying at least one model parameter such that at least one simulated process characteristic of the in situ process matches or approximates at least one real process characteristic of the in situ process; assessing one or more modified simulated process characteristics based on the modified model parameters; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation simulated process characteristics based on the modified model parameters.
 5257. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: assessing at least one operating condition of the in situ process using a simulation method based on one or more model parameter; modifying at least one model parameter such that at least one simulated process characteristic of the in situ process matches or approximates at least one real process characteristic of the in situ process; assessing one or more modified simulated process characteristics based on the modified model parameters; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5258. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing one or more model parameters to the computer system; assessing one or more first process characteristics based on one or more model parameters using a first simulation method on the computer system; assessing one or more second process characteristics based on one or more model parameters using a second simulation method on the computer system; modifying one or more model parameters such that at least one first process characteristic matches or approximates at least one second process characteristic; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5259. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing one or more model parameters to the computer system; assessing one or more first process characteristics based on one or more model parameters using a first simulation method on the computer system; assessing one or more second process characteristics based on one or more model parameters using a second simulation method on the computer system; modifying one or more model parameters such that at least one first process characteristic matches at least one second process characteristic; and wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 5260. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing to the computer system one or more values of at least one operating condition of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; assessing one or more values of at least one process characteristic corresponding to one or more values of at least one operating condition using a simulation method; providing a desired value of at least one process characteristic for the in situ process to the computer system; and assessing a desired value of at least one operating condition to achieve the desired value of at least one process characteristic from the assessed values of at least one process characteristic and the provided values of at least one operating condition.
 5261. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing to the computer system one or more values of at least one operating condition of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; assessing one or more values of at least one process characteristic corresponding to one or more values of at least one operating condition using a simulation method; providing a desired value of at least one process characteristic for the in situ process to the computer system; and assessing a desired value of at least one operating condition to achieve the desired value of at least one process characteristic from the assessed values of at least one process characteristic and the provided values of at least one operating condition.
 5262. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing a desired value of at least one process characteristic for the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and assessing a value of at least one operating condition to achieve the desired value of at least one process characteristic, wherein such assessing comprises using a relationship between at least one process characteristic and at least one operating condition for the in situ process, wherein such relationship is stored on a database accessible by the computer system.
 5263. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing a desired value of at least one process characteristic for the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and assessing a value of at least one operating condition to achieve the desired value of at least one process characteristic, wherein such assessing comprises using a relationship between at least one process characteristic and at least one operating condition for the in situ process, wherein such relationship is stored on a database accessible by the computer system.
 5264. A method of using a computer system for operating an in situ process for treating a relatively permeable formation, comprising: operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing at least one operating parameter of the in situ process to the computer system; and using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process.
 5265. The method of claim 5264, wherein one or more of the operating parameters comprise a thickness of a treated portion of the formation.
 5266. The method of claim 5264, wherein one or more of the operating parameters comprise an area of a treated portion of the formation.
 5267. The method of claim 5264, wherein one or more of the operating parameters comprise a volume of a treated portion of the formation.
 5268. The method of claim 5264, wherein one or more of the operating parameters comprise a property of the formation.
 5269. The method of claim 5264, wherein one or more of the operating parameters comprise a heat capacity of the formation.
 5270. The method of claim 5264, wherein one or more of the operating parameters comprise a permeability of the formation.
 5271. The method of claim 5264, wherein one or more of the operating parameters comprise a density of the formation.
 5272. The method of claim 5264, wherein one or more of the operating parameters comprise a thermal conductivity of the formation.
 5273. The method of claim 5264, wherein one or more of the operating parameters comprise a porosity of the formation.
 5274. The method of claim 5264, wherein one or more of the operating parameters comprise a pressure.
 5275. The method of claim 5264, wherein one or more of the operating parameters comprise a temperature.
 5276. The method of claim 5264, wherein one or more of the operating parameters comprise a heating rate.
 5277. The method of claim 5264, wherein one or more of the operating parameters comprise a process time.
 5278. The method of claim 5264, wherein one or more of the operating parameters comprises a location of producer wells.
 5279. The method of claim 5264, wherein one or more of the operating parameters comprise an orientation of producer wells.
 5280. The method of claim 5264, wherein one or more of the operating parameters comprise a ratio of producer wells to heater wells.
 5281. The method of claim 5264, wherein one or more of the operating parameters comprise a spacing between heater wells.
 5282. The method of claim 5264, wherein one or more of the operating parameters comprise a distance between an overburden and horizontal heater wells.
 5283. The method of claim 5264, wherein one or more of the operating parameters comprise a type of pattern of heater wells.
 5284. The method of claim 5264, wherein one or more of the operating parameters comprise an orientation of heater wells.
 5285. The method of claim 5264, wherein one or more of the operating parameters comprise a mechanical property.
 5286. The method of claim 5264, wherein one or more of the operating parameters comprise subsidence of the formation.
 5287. The method of claim 5264, wherein one or more of the operating parameters comprise fracture progression in the formation.
 5288. The method of claim 5264, wherein one or more of the operating parameters comprise heave of the formation.
 5289. The method of claim 5264, wherein one or more of the operating parameters comprise compaction of the formation.
 5290. The method of claim 5264, wherein one or more of the operating parameters comprise shear deformation of the formation.
 5291. The method of claim 5264, wherein the assessed information comprises information relating to properties of the formation.
 5292. The method of claim 5264, wherein the assessed information comprises a relationship between one or more operating parameters and at least one other operating parameter.
 5293. The method of claim 5264, wherein the computer system is remote from the in situ process.
 5294. The method of claim 5264, wherein the computer system is located at or near the in situ process.
 5295. The method of claim 5264, wherein at least one parameter is provided to the computer system using hardwire communication.
 5296. The method of claim 5264, wherein at least one parameter is provided to the computer system using internet communication.
 5297. The method of claim 5264, wherein at least one parameter is provided to the computer system using wireless communication.
 5298. The method of claim 5264, wherein the one or more parameters are monitored using sensors in the formation.
 5299. The method of claim 5264, wherein at least one parameter is provided automatically to the computer system.
 5300. The method of claim 5264, wherein using at least one parameter with a simulation method comprises performing a simulation and obtaining properties of the formation.
 5301. A method of using a computer system for operating an in situ process for treating a relatively permeable formation, comprising: operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing at least one operating parameter of the in situ process to the computer system; using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process; and using the assessed information to operate the in situ process.
 5302. The method of claim 5301, further comprising providing the assessed information to a computer system used for controlling the in situ process.
 5303. The method of claim 5301, wherein the computer system is remote from the in situ process.
 5304. The method of claim 5301, wherein the computer system is located at or near the in situ process.
 5305. The method of claim 5301, wherein using the assessed information to operate the in situ process comprises: modifying at least one operating parameter; and operating the in situ process with at least one modified operating parameter.
 5306. A method of using a computer system for operating an in situ process for treating a relatively permeable formation, comprising operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing at least one operating parameter of the in situ process to the computer system; using at least one parameter with a first simulation method and the computer system to provide assessed information about the in situ process; and obtaining information from a second simulation method and the computer system using the assessed information and a desired parameter.
 5307. The method of claim 5306, further comprising using the obtained information to operate the in situ process.
 5308. The method of claim 5306, wherein the first simulation method is the same as the second simulation method.
 5309. The method of claim 5306, further comprising providing the obtained information to a computer system used for controlling the in situ process.
 5310. The method of claim 5306, wherein using the obtained information to operate the in situ process comprises: modifying at least one operating parameter; and operating the in situ process with at least one modified operating parameter.
 5311. The method of claim 5306, wherein the obtained information comprises at least one operating parameter for use in the in situ process that achieves the desired parameter.
 5312. The method of claim 5306, wherein the computer system is remote from the in situ process.
 5313. The method of claim 5306, wherein the computer system is located at or near the in situ process.
 5314. The method of claim 5306, wherein the desired parameter comprises a selected gas to oil ratio.
 5315. The method of claim 5306, wherein the desired parameter comprises a selected production rate of fluid produced from the formation.
 5316. The method of claim 5306, wherein the desired parameter comprises a selected production rate of fluid at a selected time produced from the formation.
 5317. The method of claim 5306, wherein the desired parameter comprises a selected olefin content of produced fluids.
 5318. The method of claim 5306, wherein the desired parameter comprises a selected carbon number distribution of produced fluids.
 5319. The method of claim 5306, wherein the desired parameter comprises a selected ethene to ethane ratio of produced fluids.
 5320. The method of claim 5306, wherein the desired parameter comprises a desired atomic carbon to hydrogen ratio of produced fluids.
 5321. The method of claim 5306, wherein the desired parameter comprises a selected gas to oil ratio of produced fluids.
 5322. The method of claim 5306, wherein the desired parameter comprises a selected pressure in the formation.
 5323. The method of claim 5306, wherein the desired parameter comprises a selected total mass recovery from the formation.
 5324. The method of claim 5306, wherein the desired parameter comprises a selected production rate of fluid produced from the formation.
 5325. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for operating an in situ process for treating a relatively permeable formation, comprising: operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing at least one operating parameter of the in situ process to the computer system; and using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process.
 5326. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing at least one operating parameter of the in situ process to the computer system; and using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process.
 5327. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for operating an in situ process for treating a relatively permeable formation, comprising: operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing at least one operating parameter of the in situ process to the computer system; using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process; and using the assessed information to operate the in situ process.
 5328. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing at least one operating parameter of the in situ process to the computer system; using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process; and using the assessed information to operate the in situ process.
 5329. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for operating an in situ process for treating a relatively permeable formation, comprising: operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing at least one operating parameter of the in situ process to the computer system; using at least one parameter with a first simulation method and the computer system to provide assessed information about the in situ process; and obtaining information from a second simulation method and the computer system using the assessed information and a desired parameter.
 5330. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing at least one operating parameter of the in situ process to the computer system; using at least one parameter with a first simulation method and the computer system to provide assessed information about the in situ process; and obtaining information from a second simulation method and the computer system using the assessed information and a desired parameter.
 5331. A method of modeling one or more stages of a process for treating a relatively permeable formation in situ with a simulation method using a computer system, comprising: providing at least one property of the formation to the computer system; providing at least one operating condition for the one or more stages of the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; assessing at least one process characteristic of the one or more stages using the simulation method.
 5332. The method of claim 5331, wherein the simulation method is a body-fitted finite difference simulation method.
 5333. The method of claim 5331, wherein the simulation method is a reservoir simulation method.
 5334. The method of claim 5331, wherein the simulation method is a space-fitted finite difference simulation method.
 5335. The method of claim 5331, wherein the simulation method simulates heating of the formation.
 5336. The method of claim 5331, wherein the simulation method simulates fluid flow in the formation.
 5337. The method of claim 5331, wherein the simulation method simulates mass transfer in the formation.
 5338. The method of claim 5331, wherein the simulation method simulates heat transfer in the formation.
 5339. The method of claim 5331, wherein the simulation method simulates chemical reactions in the one or more stages of the process in the formation.
 5340. The method of claim 5331, wherein the simulation method simulates removal of contaminants from the formation.
 5341. The method of claim 5331, wherein the simulation method simulates recovery of heat from the formation.
 5342. The method of claim 5331, wherein the simulation method simulates injection of fluids into the formation.
 5343. The method of claim 5331, wherein the one or more stages comprise heating of the formation.
 5344. The method of claim 5331, wherein the one or more stages comprise generation of pyrolyzation fluids.
 5345. The method of claim 5331, wherein the one or more stages comprise remediation of the formation.
 5346. The method of claim 5331, wherein the one or more stages comprise shut-in of the formation.
 5347. The method of claim 5331, wherein at least one operating condition of a remediation stage is the flow rate of ground water into the formation.
 5348. The method of claim 5331, wherein at least one operating condition of a remediation stage is the flow rate of injected fluids into the formation.
 5349. The method of claim 5331, wherein at least one process characteristic of a remediation stage is the concentration of contaminants in the formation.
 5350. The method of claim 5331, further comprising: providing to the computer system at least one set of operating conditions for at least one of the stages of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing to the computer system at least one desired process characteristic for at least one of the stages of the in situ process; and assessing at least one additional operating condition for at least one of the stages that achieves at least one desired process characteristic for at least one of the stages.
 5351. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: providing at least one property of the formation to a computer system; providing at least one operating condition to the computer system; assessing at least one process characteristic of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and assessing at least one deformation characteristic of the formation using a simulation method from at least one property, at least one operating condition, and at least one process characteristic.
 5352. The method of claim 5351, wherein the in situ process comprises two or more heat sources.
 5353. The method of claim 5351, wherein the in situ process provides heat from one or more heat sources to at least one portion of the formation.
 5354. The method of claim 5351, wherein the simulation method comprises a finite element simulation method.
 5355. The method of claim 5351, wherein the formation comprises a treated portion and an untreated portion.
 5356. The method of claim 5351, wherein at least one deformation characteristic comprises subsidence.
 5357. The method of claim 5351, wherein at least one deformation characteristic comprises heave.
 5358. The method of claim 5351, wherein at least one deformation characteristic comprises compaction.
 5359. The method of claim 5351, wherein at least one deformation characteristic comprises shear deformation.
 5360. The method of claim 5351, wherein at least one operating condition comprises a pressure.
 5361. The method of claim 5351, wherein at least one operating condition comprises a temperature.
 5362. The method of claim 5351, wherein at least one operating condition comprises a process time.
 5363. The method of claim 5351, wherein at least one operating condition comprises a rate of pressure increase.
 5364. The method of claim 5351, wherein at least one operating condition comprises a heating rate.
 5365. The method of claim 5351, wherein at least one operating condition comprises a width of a treated portion of the formation.
 5366. The method of claim 5351, wherein at least one operating condition comprises a thickness of a treated portion of the formation.
 5367. The method of claim 5351, wherein at least one operating condition comprises a thickness of an overburden of the formation.
 5368. The method of claim 5351, wherein at least one process characteristic comprises a pore pressure distribution in the formation.
 5369. The method of claim 5351, wherein at least one process characteristic comprises a temperature distribution in the formation.
 5370. The method of claim 5351, wherein at least one process characteristic comprises a heat input rate.
 5371. The method of claim 5351, wherein at least one property comprises a physical property of the formation.
 5372. The method of claim 5351, wherein at least one property comprises richness of the formation.
 5373. The method of claim 5351, wherein at least one property comprises a heat capacity.
 5374. The method of claim 5351, wherein at least one property comprises a thermal conductivity.
 5375. The method of claim 5351, wherein at least one property comprises a coefficient of thermal expansion.
 5376. The method of claim 5351, wherein at least one property comprises a mechanical property.
 5377. The method of claim 5351, wherein at least one property comprises an elastic modulus.
 5378. The method of claim 5351, wherein at least one property comprises a Poisson's ratio.
 5379. The method of claim 5351, wherein at least one property comprises cohesion stress.
 5380. The method of claim 5351, wherein at least one property comprises a friction angle.
 5381. The method of claim 5351, wherein at least one property comprises a cap eccentricity.
 5382. The method of claim 5351, wherein at least one property comprises a cap yield stress.
 5383. The method of claim 5351, wherein at least one property comprises a cohesion creep multiplier.
 5384. The method of claim 5351, wherein at least one property comprises a thermal expansion coefficient.
 5385. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: providing to the computer system at least one set of operating conditions for the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing to the computer system at least one desired deformation characteristic for the in situ process; and assessing at least one additional operating condition of the formation that achieves at least one desired deformation characteristic.
 5386. The method of claim 5385, further comprising operating the in situ system using at least one additional operating condition.
 5387. The method of claim 5385, wherein the in situ process comprises two or more heat sources.
 5388. The method of claim 5385, wherein the in situ process provides heat from one or more heat sources to at least one portion of the formation.
 5389. The method of claim 5385, wherein the in situ process allows heat to transfer from one or more heat sources to a selected section of the formation.
 5390. The method of claim 5385, wherein at least one set of operating conditions comprises at least one set of pressures.
 5391. The method of claim 5385, wherein at least one set of operating conditions comprises at least one set of temperatures.
 5392. The method of claim 5385, wherein at least one set of operating conditions comprises at least one set of heating rates.
 5393. The method of claim 5385, wherein at least one set of operating conditions comprises at least one set of overburden thicknesses.
 5394. The method of claim 5385, wherein at least one set of operating conditions comprises at least one set of thicknesses of a treated portion of the formation.
 5395. The method of claim 5385, wherein at least one set of operating conditions comprises at least one set of widths of a treated portion of the formation.
 5396. The method of claim 5385, wherein at least one set of operating conditions comprises at least one set of radii of a treated portion of the formation.
 5397. The method of claim 5385, wherein at least one desired deformation characteristic comprises a selected subsidence.
 5398. The method of claim 5385, wherein at least one desired deformation characteristic comprises a selected heave.
 5399. The method of claim 5385, wherein at least one desired deformation characteristic comprises a selected compaction.
 5400. The method of claim 5385, wherein at least one desired deformation characteristic comprises a selected shear deformation.
 5401. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: providing one or more values of at least one operating condition; assessing one or more values of at least one deformation characteristic using a simulation method based on the one or more values of at least one operating condition; providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and assessing a desired value of at least one operating condition that achieves the desired value of at least one deformation characteristic from the determined values of at least one deformation characteristic and the provided values of at least one operating condition.
 5402. The method of claim 5401, further comprising operating the in situ process using the desired value of at least one operating condition.
 5403. The method of claim 5401, wherein the in situ process comprises two or more heat sources.
 5404. The method of claim 5401, wherein at least one operating condition comprises a pressure.
 5405. The method of claim 5401, wherein at least one operating condition comprises a heat input rate.
 5406. The method of claim 5401, wherein at least one operating condition comprises a temperature.
 5407. The method of claim 5401, wherein at least one operating condition comprises a heating rate.
 5408. The method of claim 5401, wherein at least one operating condition comprises an overburden thickness.
 5409. The method of claim 5401, wherein at least one operating condition comprises a thickness of a treated portion of the formation.
 5410. The method of claim 5401, wherein at least one operating condition comprises a width of a treated portion of the formation.
 5411. The method of claim 5401, wherein at least one operating condition comprises a radius of a treated portion of the formation.
 5412. The method of claim 5401, wherein at least one deformation characteristic comprises subsidence.
 5413. The method of claim 5401, wherein at least one deformation characteristic comprises heave.
 5414. The method of claim 5401, wherein at least one deformation characteristic comprises compaction.
 5415. The method of claim 5401, wherein at least one deformation characteristic comprises shear deformation.
 5416. The method of claim 5401, wherein a value of at least one formation characteristic comprises the formation characteristic as a function of time.
 5417. The method of claim 5401, further comprising determining a value of at least one deformation characteristic based on the desired value of at least one operating condition using the simulation method.
 5418. The method of claim 5401, wherein determining the desired value of at least one operating condition comprises interpolating the desired value from the determined values of at least one formation characteristic and the provided values of at least one operating condition.
 5419. A method of using a computer system for modeling an in situ process for treating a relatively permeable formation, comprising: providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and assessing a value of at least one operating condition to achieve the desired value of at least one deformation characteristic from a database in memory on the computer system comprising a relationship between at least one deformation characteristic and at least one operating condition for the in situ process.
 5420. The method of claim 5419, further comprising operating the in situ system using the desired value of at least one operating condition.
 5421. The method of claim 5419, wherein the in situ system comprises two or more heat sources.
 5422. The method of claim 5419, wherein the relationship is determined from one or more simulations of the in situ process using a simulation method.
 5423. The method of claim 5419, wherein the relationship comprises one or more values of at least one deformation characteristic and corresponding values of at least one operating condition.
 5424. The method of claim 5419, wherein the relationship comprises an analytical function.
 5425. The method of claim 5419, wherein determining a value of at least one operating condition comprises interpolating a value of at least one operating condition from the relationship.
 5426. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing at least one property of the formation to a computer system; providing at least one operating condition to the computer system; determining at least one process characteristic of the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and determining at least one deformation characteristic of the formation using a simulation method from at least one property, at least one operating condition, and at least one process characteristic.
 5427. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing at least one property of the formation to a computer system; providing at least one operating condition to the computer system; determining at least one process characteristic of the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and determining at least one deformation characteristic of the formation using a simulation method from at least one property, at least one operating condition, and at least one process characteristic.
 5428. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing to the computer system at least one set of operating conditions for the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing to the computer system at least one desired deformation characteristic for the in situ process; and determining at least one additional operating condition of the formation that achieves at least one desired deformation characteristic.
 5429. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing to the computer system at least one set of operating conditions for the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing to the computer system at least one desired deformation characteristic for the in situ process; and determining at least one additional operating condition of the formation that achieves at least one desired deformation characteristic.
 5430. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing one or more values of at least one operating condition; determining one or more values of at least one deformation characteristic using a simulation method based on the one or more values of at least one operating condition; providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and determining a desired value of at least one operating condition that achieves the desired value of at least one deformation characteristic from the determined values of at least one deformation characteristic and the provided values of at least one operating condition.
 5431. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing one or more values of at least one operating condition; determining one or more values of at least one deformation characteristic using a simulation method based on the one or more values of at least one operating condition; providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and determining a desired value of at least one operating condition that achieves the desired value of at least one deformation characteristic from the determined values of at least one deformation characteristic and the provided values of at least one operating condition.
 5432. A system, comprising: a CPU; a data memory coupled to the CPU; and a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating a relatively permeable formation, the method comprising: providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and determining a value of at least one operating condition to achieve the desired value of at least one deformation characteristic from a database in memory on the computer system comprising a relationship between at least one formation characteristic and at least one operating condition for the in situ process.
 5433. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising: providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and determining a value of at least one operating condition to achieve the desired value of at least one deformation characteristic from a database in memory on the computer system comprising a relationship between at least one formation characteristic and at least one operating condition for the in situ process.
 5434. A system configurable to provide heat to a relatively permeable formation, comprising: a first oxidizer configurable to be placed in an opening in the formation, wherein the first oxidizer is configurable to oxidize a first fuel during use; a second oxidizer configurable to be placed in the opening, wherein the second oxidizer is configurable to oxidize a second fuel during use; and wherein the system is configurable to allow heat from oxidation of the first fuel or the second fuel to transfer to the formation during use.
 5435. The system of claim 5434, wherein the system is configured to provide heat to the relatively permeable formation.
 5436. The system of claim 5434, wherein the first oxidizer is configured to be placed in an opening in the formation and wherein the first oxidizer is configured to oxidize the first fuel during use.
 5437. The system of claim 5434, wherein the second oxidizer is configured to be placed in the opening and wherein the second oxidizer is configured to oxidize the second fuel during use.
 5438. The system of claim 5434, wherein the system is configured to allow the heat from the oxidation to transfer to the formation during use.
 5439. The system of claim 5434, wherein the first oxidizer comprises a burner.
 5440. The system of claim 5434, wherein the first oxidizer comprises an inline burner.
 5441. The system of claim 5434, wherein the second oxidizer comprises a burner.
 5442. The system of claim 5434, wherein the second oxidizer comprises a ring burner.
 5443. The system of claim 5434, wherein a distance between the first oxidizer and the second oxidizer is less than about 250 meters.
 5444. The system of claim 5434, further comprising a conduit configurable to be placed in the opening.
 5445. The system of claim 5434, further comprising a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide an oxidizing fluid to the first oxidizer during use.
 5446. The system of claim 5434, further comprising a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide the first fuel to the first to oxidizer during use.
 5447. The system of claim 5434, further comprising a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide an oxidizing fluid to the second oxidizer during use.
 5448. The system of claim 5434, further comprising a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide the second fuel to the second oxidizer during use.
 5449. The system of claim 5434, further comprising a third oxidizer configurable to be placed in the opening, wherein the third oxidizer is configurable to oxidize a third fuel during use.
 5450. The system of claim 5434, further comprising a fuel source, wherein the fuel source is configurable to provide the first fuel to the first oxidizer or the second fuel to the second oxidizer during use.
 5451. The system of claim 5434, wherein the first fuel is different from the second fuel.
 5452. The system of claim 5434, wherein the first fuel is different from the second fuel, wherein the second fuel comprises hydrogen.
 5453. The system of claim 5434, wherein a flow of the first fuel is separately controlled from a flow of the second fuel.
 5454. The system of claim 5434, wherein the first oxidizer is configurable to be placed proximate an upper portion of the opening.
 5455. The system of claim 5434, wherein the second oxidizer is configurable to be placed proximate a lower portion of the opening.
 5456. The system of claim 5434, further comprising insulation configurable to be placed proximate the first oxidizer.
 5457. The system of claim 5434, further comprising insulation configurable to be placed proximate the second oxidizer.
 5458. The system of claim 5434, wherein products from oxidation of the first fuel or the second fuel are removed from the formation through the opening during use.
 5459. The system of claim 5434, further comprising an exhaust conduit configurable to be coupled to the opening to allow exhaust fluid to flow from the formation through the exhaust conduit during use.
 5460. The system of claim 5434, wherein the system is configured to allow the heat from the oxidation of the first fuel or the second fuel to transfer to the formation during use.
 5461. The system of claim 5434, wherein the system is configured to allow the heat from the oxidation to transfer to a pyrolysis zone in the formation during use.
 5462. The system of claim 5434, wherein the system is configured to allow the heat from the oxidation to transfer to a pyrolysis zone in the formation during use, and wherein the transferred heat causes pyrolysis of at least some hydrocarbons in the pyrolysis zone during use.
 5463. The system of claim 5434, wherein at least some of the heat from the oxidation is generated at the first oxidizer.
 5464. The system of claim 5434, wherein at least some of the heat from the oxidation is generated at the second oxidizer.
 5465. The system of claim 5434, wherein a combination of heat from the first oxidizer and heat from the second oxidizer substantially uniformly heats a portion of the formation during use.
 5466. The system of claim 5434, further comprising a first conduit configurable to be placed in the opening of the formation, wherein the first conduit is configurable to provide a first oxidizing fluid to the first oxidizer in the opening during use, and wherein the first conduit is further configurable to provide a second oxidizing fluid to the second oxidizer in the opening during use.
 5467. The system of claim 5466, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide the first fuel to the first oxidizer during use.
 5468. The system of claim 5467, wherein the fuel conduit is further configurable to be placed in the first conduit.
 5469. The system of claim 5467, wherein the first conduit is further configurable to be placed in the fuel conduit.
 5470. The system of claim 5466, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide the second fuel to the second oxidizer during use.
 5471. The system of claim 5466, wherein the first conduit is further configurable to provide the first fuel to the first oxidizer during use.
 5472. An in situ method for heating a relatively permeable formation, comprising: providing a first oxidizing fluid to a first oxidizer placed in an opening in the formation; providing a first fuel to the first oxidizer; oxidizing at least some of the first fuel in the first oxidizer; providing a second oxidizing fluid to a second oxidizer placed in the opening in the formation; providing a second fuel to the second oxidizer; oxidizing at least some of the second fuel in the second oxidizer; and allowing heat from oxidation of the first fuel and the second fuel to transfer to a portion of the formation.
 5473. The method of claim 5472, wherein the first oxidizing fluid is provided to the first oxidizer through a conduit placed in the opening.
 5474. The method of claim 5472, wherein the second oxidizing fluid is provided to the second oxidizer through a conduit placed in the opening.
 5475. The method of claim 5472, wherein the first fuel is provided to the first oxidizer through a conduit placed in the opening.
 5476. The method of claim 5472, wherein the first fuel is provided to the second oxidizer through a conduit placed in the opening.
 5477. The method of claim 5472, wherein the first oxidizing fluid and the first fuel are provided to the first oxidizer through a conduit placed in the opening.
 5478. The method of claim 5472, further comprising using exhaust fluid from the first oxidizer as a portion of the second fuel used in the second oxidizer.
 5479. The method of claim 5472, further comprising allowing the heat to transfer substantially by conduction from the portion of the formation to a pyrolysis zone of the formation.
 5480. The method of claim 5472, further comprising initiating oxidation of the second fuel in the second oxidizer with an ignition source.
 5481. The method of claim 5472, further comprising removing exhaust fluids through the opening.
 5482. The method of claim 5472, further comprising removing exhaust fluids through the opening, wherein the exhaust fluids comprise heat and allowing at least some heat in the exhaust fluids to transfer from the exhaust fluids to the first oxidizing fluid prior to oxidation in the first oxidizer.
 5483. The method of claim 5472, further comprising removing exhaust fluids comprising heat through the opening, allowing at least some heat in the exhaust fluids to transfer from the exhaust fluids to the first oxidizing fluid prior to oxidation, and increasing a thermal efficiency of heating the relatively permeable formation.
 5484. The method of claim 5472, further comprising removing exhaust fluids through an exhaust conduit coupled to the opening.
 5485. The method of claim 5472, further comprising removing exhaust fluids through an exhaust conduit coupled to the opening and providing at least a portion of the exhaust fluids to a fourth oxidizer to be used as a fourth fuel in a fourth oxidizer, wherein the fourth oxidizer is located in a separate opening in the formation.
 5486. A system configurable to provide heat to a relatively permeable formation, comprising: an opening placed in the formation, wherein the opening comprises a first elongated portion, a second elongated portion, and a third elongated portion, wherein the second elongated portion diverges from the first elongated portion in a first direction, wherein the third elongated portion diverges from the first elongated portion in a second direction, and wherein the first direction is substantially different than the second direction; a first heater configurable to be placed in the second elongated portion, wherein the first heater is configurable to heat at least a portion of the formation during use; a second heater configurable to be placed in the third elongated portion, wherein the second heater is configurable to heat to at least a portion of the formation during use; and wherein the system is configurable to allow heat to transfer to the formation during use.
 5487. The system of claim 5486, wherein the first heater and the second heater are configurable to heat to at least a portion of the formation during use.
 5488. The system of claim 5486, wherein the second and the third elongated portions are oriented substantially horizontally within the formation.
 5489. The system of claim 5486, wherein the first direction is about 180° opposite the second direction.
 5490. The system of claim 5486, wherein the first elongated portion is placed substantially within an overburden of the formation.
 5491. The system of claim 5486, wherein the transferred heat substantially uniformly heats a portion of the formation during use.
 5492. The system of claim 5486, wherein the first heater or the second heater comprises a downhole combustor.
 5493. The system of claim 5486, wherein the first heater or the second heater comprises an insulated conductor heater.
 5494. The system of claim 5486, wherein the first heater or the second heater comprises a conductor-in-conduit heater.
 5495. The system of claim 5486, wherein the first heater or the second heater comprises an elongated member heater.
 5496. The system of claim 5486, wherein the first heater or the second heater comprises a natural distributed combustor heater.
 5497. The system of claim 5486, wherein the first heater or the second heater comprises a flameless distributed combustor heater.
 5498. The system of claim 5486, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer.
 5499. The system of claim 5498, wherein the second elongated portion has a length of less than about 175 meters.
 5500. The system of claim 5498, wherein the third elongated portion has a length of less than about 175 meters.
 5501. The system of claim 5498, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide fuel to the first oxidizer during use.
 5502. The system of claim 5498, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide fuel to the second oxidizer during use.
 5503. The system of claim 5498, further comprising a fuel source, wherein the fuel source is configurable to provide fuel to the first oxidizer or the second oxidizer during use.
 5504. The system of claim 5498, further comprising a third oxidizer placed within the first elongated portion of the opening.
 5505. The system of claim 5504, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide fuel to the third oxidizer during use.
 5506. The system of claim 5504, further comprising a first fuel source configurable to provide a first fuel to the first fuel conduit, a second fuel source configurable to provide a second fuel to a second fuel conduit, and a third fuel source configurable to provide a third fuel to a third fuel conduit.
 5507. The system of claim 5506, wherein the first fuel has a composition substantially different from the second fuel or the third fuel.
 5508. The system of claim 5486, further comprising insulation configurable to be placed proximate the first heater.
 5509. The system of claim 5486, further comprising insulation configurable to be placed proximate the second heater.
 5510. The system of claim 5486, wherein a fuel is oxidized in the first heater or the second heater to generate heat and wherein products from oxidation are removed from the formation through the opening during use.
 5511. The system of claim 5486, wherein a fuel is oxidized in the first heater and the second heater and wherein products from oxidation are removed from the formation through the opening during use.
 5512. The system of claim 5486, further comprising an exhaust conduit configurable to be coupled to the opening to allow exhaust fluid to flow from the formation through the exhaust conduit during use.
 5513. The system of claim 5498, wherein the system is configured to allow the heat from oxidation of fuel to transfer to the formation during use.
 5514. The system of claim 5486, wherein the system is configured to allow heat to transfer to a pyrolysis zone in the formation during use.
 5515. The system of claim 5486, wherein the system is configured to allow heat to transfer to a pyrolysis zone in the formation during use, and wherein the transferred heat causes pyrolysis of at least some hydrocarbons within the pyrolysis zone during use.
 5516. The system of claim 5486, wherein a combination of the heat generated from the first heater and the heat generated from the second heater substantially uniformly heats a portion of the formation during use.
 5517. The system of claim 5486, further comprising a third heater placed in the second elongated portion.
 5518. The system of claim 5517, wherein the third heater comprises a downhole combustor.
 5519. The system of claim 5517, further comprising a fourth heater placed in the third elongated portion.
 5520. The system of claim 5519, wherein the fourth heater comprises a downhole combustor.
 5521. The system of claim 5486, wherein the first heater is configured to be placed in the second elongated portion, wherein the first heater is configured to provide heat to at least a portion of the formation during use, wherein the second heater is configured to be placed in the third elongated portion, wherein the second heater is configured to provide heat to at least a portion of the formation during use, and wherein the system is configured to allow heat to transfer to the formation during use.
 5522. The system of claim 5486, wherein the second and the third elongated portions are located in a substantially similar plane.
 5523. The system of claim 5522, wherein the opening comprises a fourth elongated portion and a fifth elongated portion, wherein the fourth elongated portion diverges from the first elongated portion in a third direction, wherein the fifth elongated portion diverges from the first elongated portion in a fourth direction, and wherein the third direction is substantially different than the fourth direction.
 5524. The system of claim 5523, wherein the fourth and fifth elongated portions are located in a plane substantially different than the second and the third elongated portions.
 5525. The system of claim 5523, wherein a third heater is configurable to be placed in the fourth elongated portion, and wherein a fourth heater is configurable to be placed in the fifth elongated portion.
 5526. An in situ method for heating a relatively permeable formation, comprising: providing heat from two or more heaters placed in an opening in the formation, wherein the opening comprises a first elongated portion, a second elongated portion, and a third elongated portion, wherein the second elongated portion diverges from the first elongated portion in a first direction, wherein the third elongated portion diverges from the first elongated portion in a second direction, and wherein the first direction is substantially different than the second direction; allowing heat from the two or more heaters to transfer to a portion of the formation; and wherein the two or more heaters comprise a first heater placed in the second elongated portion and a second heater placed in the third elongated portion.
 5527. The method of claim 5526, wherein the second and the third elongated portions are oriented substantially horizontally within the formation.
 5528. The method of claim 5526, wherein the first elongated portion is located substantially within an overburden of the formation.
 5529. The method of claim 5526, further comprising substantially uniformly heating a portion of the formation.
 5530. The method of claim 5526, wherein the first heater or the second heater comprises a downhole combustor.
 5531. The method of claim 5526, wherein the first heater or the second heater comprises an insulated conductor heater.
 5532. The method of claim 5526, wherein the first heater or the second heater comprises a conductor-in-conduit heater.
 5533. The method of claim 5526, wherein the first heater or the second heater comprises an elongated member heater.
 5534. The method of claim 5526, wherein the first heater or the second heater comprises a natural distributed combustor heater.
 5535. The method of claim 5526, wherein the first heater or the second heater comprises a flameless distributed combustor heater.
 5536. The method of claim 5526, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer.
 5537. The method of claim 5526, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer and further comprising providing fuel to the first oxidizer through a fuel conduit placed in the opening.
 5538. The method of claim 5526, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer and further comprising providing fuel to the second oxidizer through a fuel conduit placed in the opening.
 5539. The method of claim 5526, wherein the two or more heaters comprise oxidizers and further comprising providing fuel to the oxidizers from a fuel source.
 5540. The method of claim 5536, further comprising providing heat to a portion of the formation using a third oxidizer placed within the first elongated portion of the opening.
 5541. The method of claim 5526, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer further comprising: providing heat to a portion of the formation using a third oxidizer placed within the first elongated portion of the opening; and providing fuel to the third oxidizer through a fuel conduit placed in the opening.
 5542. The method of claim 5526, wherein the two or more heaters comprise oxidizers, and further comprising providing heat by oxidizing a fuel within the oxidizers and removing products of oxidation of fuel through the opening.
 5543. The method of claim 5526, wherein the two or more heaters comprise oxidizers, and further comprising removing products from oxidation of fuel through an exhaust conduit coupled to the opening.
 5544. The method of claim 5526, further comprising allowing the heat to transfer from the portion to a pyrolysis zone in the formation.
 5545. The method of claim 5526, further comprising allowing the heat to transfer from the portion to a pyrolysis zone in the formation and pyrolyzing at least some hydrocarbons within the pyrolysis zone with the transferred heat.
 5546. The method of claim 5526, further comprising allowing the heat to transfer to from the portion to a pyrolysis zone in the formation, pyrolyzing at least some hydrocarbons within the pyrolysis zone with the transferred heat, and producing a portion of the pyrolyzed hydrocarbons through a conduit placed in the first elongated portion.
 5547. The method of claim 5526, further comprising providing heat to a portion of the formation using a third heater placed in the second elongated portion.
 5548. The method of claim 5547, wherein the third heater comprises a downhole combustor.
 5549. The method of claim 5547, further comprising providing heat to a portion of the formation using a fourth heater placed in the third elongated portion.
 5550. The method of claim 5549, wherein the fourth heater comprises a downhole combustor.
 5551. A system configurable to provide heat to a relatively permeable formation, comprising: an oxidizer configurable to be placed in an opening in the formation, wherein the oxidizer is configurable to oxidize fuel to generate heat during use; a first conduit configurable to be placed in the opening of the formation, wherein the first conduit is configurable to provide oxidizing fluid to the oxidizer in the opening during use; a heater configurable to be placed in the opening and configurable to provide additional heat; and wherein the system is configurable to allow the generated heat and the additional heat to transfer to the formation during use.
 5552. The system of claim 5551, wherein the heater comprises an insulated conductor.
 5553. The system of claim 5551, wherein the heater comprises a conductor-in-conduit heater.
 5554. The system of claim 5551, wherein the heater comprises an elongated member heater.
 5555. The system of claim 5551, wherein the heater comprises a flameless distributed combustor.
 5556. The system of claim 5551, wherein the oxidizer is configurable to be placed proximate an upper portion of the opening.
 5557. The system of claim 5551, further comprising insulation configurable to be placed proximate the oxidizer.
 5558. The system of claim 5551, wherein the heater is configurable to be coupled to the first conduit.
 5559. The system of claim 5551, wherein products from the oxidation of the fuel are removed from the formation through the opening during use.
 5560. The system of claim 5551, further comprising an exhaust conduit configurable to be coupled to the opening to allow exhaust fluid to flow from the formation through the exhaust conduit during use.
 5561. The system of claim 5551, wherein the system is configured to allow the generated heat and the additional heat to transfer to the formation during use.
 5562. The system of claim 5551, wherein the system is configured to allow the generated heat and the additional heat to transfer to a pyrolysis zone in the formation during use.
 5563. The system of claim 5551, wherein the system is configured to allow the generated heat and the additional heat to transfer to a pyrolysis zone in the formation during use, and wherein the transferred heat pyrolyzes of at least some hydrocarbons within the pyrolysis zone during use.
 5564. The system of claim 5551, wherein a combination of the generate heat and the additional heat substantially uniformly heats a portion of the formation during use.
 5565. The system of claim 5551, wherein the oxidizer is configured to be placed in the opening in the formation and wherein the oxidizer is configured to oxidize at least some fuel during use.
 5566. The system of claim 5551, wherein the first conduit is configured to be placed in the opening of the formation and wherein the first conduit is configured to provide oxidizing fluid to the oxidizer in the opening during use.
 5567. The system of claim 5551, wherein the heater is configured to be placed in the opening and wherein the heater is configurable to provide heat to a portion of the formation during use.
 5568. The system of claim 5551, wherein the system is configured to allow the heat from the oxidation of at least some fuel and from the heater to transfer to the formation during use.
 5569. An in situ method for heating a relatively permeable formation, comprising: allowing heat to transfer from a heater placed in an opening to a portion of the formation; providing oxidizing fluid to an oxidizer placed in the opening in the formation; providing fuel to the oxidizer; oxidizing at least some fuel in the oxidizer; and allowing additional heat from oxidation of at least some fuel to transfer to the portion of the formation.
 5570. The method of claim 5569, wherein the heater comprises an insulated conductor.
 5571. The method of claim 5569, wherein the heater comprises a conductor-in-conduit heater.
 5572. The method of claim 5569, wherein the heater comprises an elongated member heater.
 5573. The method of claim 5569, wherein the heater comprises a flameless distributed combustor.
 5574. The method of claim 5569, wherein the oxidizer is placed proximate an upper portion of the opening.
 5575. The method of claim 5569, further comprising allowing the additional heat to transfer from the portion to a pyrolysis zone in the formation.
 5576. The method of claim 5569, further comprising allowing the additional heat to transfer from the portion to a pyrolysis zone in the formation and pyrolyzing at least some hydrocarbons within the pyrolysis zone.
 5577. The method of claim 5569, further comprising substantially uniformly heating the portion of the formation.
 5578. The method of claim 5569, further comprising removing exhaust fluids through the opening.
 5579. The method of claim 5569, further comprising removing exhaust fluids through an exhaust annulus in the formation.
 5580. The method of claim 5569, further comprising removing exhaust fluids through an exhaust conduit coupled to the opening.
 5581. A system configurable to provide heat to a relatively permeable formation, comprising: a heater configurable to be placed in an opening in the formation, wherein the heater is configurable to heat a portion of the formation to a temperature sufficient to sustain oxidation of hydrocarbons during use; an oxidizing fluid source configurable to provide an oxidizing fluid to a reaction zone of the formation to oxidize at least some hydrocarbons in the reaction zone during use such that heat is generated in the reaction zone, and wherein at least some of the reaction zone has been previously heated by the heater; a first conduit configurable to be placed in the opening, wherein the first conduit is configurable to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use, wherein the flow of oxidizing fluid can be controlled along at least a segment of the first conduit; and wherein the system is configurable to allow the generated heat to transfer from the reaction zone to the formation during use.
 5582. The system of claim 5581, wherein the system is configurable to provide hydrogen to the reaction zone during use.
 5583. The system of claim 5581, wherein the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 5584. The system of claim 5581, wherein the system is configurable to allow the generated heat to transfer from the reaction zone to a pyrolysis zone in the formation during use.
 5585. The system of claim 5581, wherein the system is configurable to allow the generated heat to transfer substantially by conduction from the reaction zone to the formation during use.
 5586. The system of claim 5581, wherein a temperature within the reaction zone can be controlled along at least a segment of the first conduit during use.
 5587. The system of claim 5581, wherein a heating rate in at least a section of the formation proximate at least a segment of the first conduit be controlled.
 5588. The system of claim 5581, wherein the oxidizing fluid is configurable to be transported through the reaction zone substantially by diffusion, and wherein a rate of diffusion of the oxidizing fluid can controlled by a temperature within the reaction zone.
 5589. The system of claim 5581, wherein the first conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening during use.
 5590. The system of claim 5581, wherein the first conduit comprises critical flow orifices, and wherein the critical flow orifices are positioned on the first conduit such that a flow rate of the oxidizing fluid is controlled at a selected rate during use.
 5591. The system of claim 5581, further comprising a second conduit configurable to remove an oxidation product during use.
 5592. The system of claim 5591, wherein the second conduit is further configurable to allow heat within the oxidation product to transfer to the oxidizing fluid in the first conduit during use.
 5593. The system of claim 5591, wherein a pressure of the oxidizing fluid in the first conduit and a pressure of the oxidation product in the second conduit are controlled during use such that a concentration of the oxidizing fluid along the length of the first conduit is substantially uniform.
 5594. The system of claim 5591, wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone during use.
 5595. The system of claim 5581, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone during use.
 5596. The system of claim 5581, wherein the portion of the formation extends radially from the opening a distance of less than approximately 3 m.
 5597. The system of claim 5581, wherein the reaction zone extends radially from the opening a distance of less than approximately 3 m.
 5598. The system of claim 5581, wherein the system is configurable to pyrolyze at least some hydrocarbons in a pyrolysis zone of the formation.
 5599. The system of claim 5581, wherein the heater is configured to be placed in an opening in the formation and wherein the heater is configured to provide the heat to at least the portion of the formation during use.
 5600. The system of claim 5581, wherein a first conduit is configured to be placed in the opening and wherein the first conduit is configured to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use.
 5601. The system of claim 5581, wherein the flow of oxidizing fluid is controlled along at least a segment of the length of the first conduit and wherein the system is configured to allow the additional heat to transfer from the reaction zone to the formation during use.
 5602. An in situ method for providing heat to a relatively permeable formation, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons with an oxidizing fluid within the portion of the formation; providing the oxidizing fluid to a reaction zone in the formation; controlling a flow of the oxidizing fluid along at least a length of the reaction zone; generating heat within the reaction zone; and allowing the generated heat to transfer to the formation.
 5603. The method of claim 5602, further comprising allowing the oxidizing fluid to react with at least some of the hydrocarbons in the reaction zone to generate the heat in the reaction zone.
 5604. The method of claim 5602, wherein at least a section of the reaction zone is proximate an opening in the formation.
 5605. The method of claim 5602, further comprising transporting the oxidizing fluid through the reaction zone substantially by diffusion.
 5606. The method of claim 5602, further comprising transporting the oxidizing fluid through the reaction zone substantially by diffusion, and controlling a rate of diffusions of the oxidizing fluid by controlling a temperature within the reaction zone.
 5607. The method of claim 5602, wherein the generated heat transfers from the reaction zone to a pyrolysis zone in the formation.
 5608. The method of claim 5602, wherein the generated heat transfers from the reaction zone to the formation substantially by conduction.
 5609. The method of claim 5602, further comprising controlling a temperature along at least a length of the reaction zone.
 5610. The method of claim 5602, further comprising controlling a flow of the oxidizing fluid along at least a length of the reaction zone, and controlling a temperature along at least a length of the reaction zone.
 5611. The method of claim 5602, further comprising controlling a heating rate along at least a length of the reaction zone.
 5612. The method of claim 5602, wherein the oxidizing fluid is provided through a conduit placed within an opening in the formation, wherein the conduit comprises orifices.
 5613. The method of claim 5602, further comprising controlling a rate of oxidation by providing the oxidizing fluid to the reaction zone from a conduit having critical flow orifices.
 5614. The method of claim 5602, wherein the oxidizing fluid is provided to the reaction zone through a conduit placed within the formation, and further comprising positioning critical flow orifices on the conduit such that the flow rate of the oxidizing fluid to at least a length of the reaction zone is controlled at a selected flow rate.
 5615. The method of claim 5602, wherein the oxidizing fluid is provided to the reaction zone from a conduit placed within an opening in the formation, and further comprising sizing critical flow orifices on the conduit such that the flow rate of the oxidizing fluid to at least a length of the reaction zone is controlled at a selected flow rate.
 5616. The method of claim 5602, further comprising increasing a volume of the reaction zone, and increasing the flow of the oxidizing fluid to the reaction zone such that a rate of oxidation within the reaction zone is substantially constant over time.
 5617. The method of claim 5602, further comprising maintaining a substantially constant rate of oxidation within the reaction zone over time.
 5618. The method of claim 5602, wherein a conduit is placed in an opening in the formation, and further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.
 5619. The method of claim 5602, further comprising removing an oxidation product from the formation through a conduit placed in an opening in the formation.
 5620. The method of claim 5602, further comprising removing an oxidation product from the formation through a conduit placed in an opening in the formation and substantially inhibiting the oxidation product from flowing into a surrounding portion of the formation.
 5621. The method of claim 5602, further comprising inhibiting the oxidizing fluid from flowing into a surrounding portion of the formation.
 5622. The method of claim 5602, further comprising removing at least some water from the formation prior to heating the portion.
 5623. The method of claim 5602, further comprising providing additional heat to the formation from an electric heater placed in the opening.
 5624. The method of claim 5602, further comprising providing additional heat to the formation from an electric heater placed in an opening in the formation such that the oxidizing fluid continuously oxidizes at least a portion of the hydrocarbons in the reaction zone.
 5625. The method of claim 5602, further comprising providing additional heat to the formation from an electric heater placed in the opening to maintain a constant heat rate in the formation.
 5626. The method of claim 5625, further comprising providing electricity to the electric heater using a wind powered device.
 5627. The method of claim 5625, further comprising providing electricity to the electric heater using a solar powered device.
 5628. The method of claim 5602, further comprising maintaining a temperature within the portion above about the temperature sufficient to support the reaction of hydrocarbons with the oxidizing fluid.
 5629. The method of claim 5602, further comprising providing additional heat to the formation from an electric heater placed in the opening and controlling the additional heat such that a temperature of the portion is greater than about the temperature sufficient to support the reaction of hydrocarbons with the oxidizing fluid.
 5630. The method of claim 5602, further comprising removing oxidation products from the formation, and generating electricity using oxidation products removed from the formation.
 5631. The method of claim 5602, further comprising removing oxidation products from the formation, and using at least some of the removed oxidation products in an air compressor.
 5632. The method of claim 5602, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone over time.
 5633. The method of claim 5602, further comprising assessing a temperature in or proximate an opening in the formation, wherein the flow of oxidizing fluid along at least a section of the reaction zone is controlled as a function of the assessed temperature.
 5634. The method of claim 5602, further comprising assessing a temperature in or proximate an opening in the formation, and increasing the flow of oxidizing fluid as the assessed temperature decreases.
 5635. The method of claim 5602, further comprising controlling the flow of oxidizing fluid to maintain a temperature in or proximate an opening in the formation at a temperature less than a pre-selected temperature.
 5636. A system configurable to provide heat to a relatively permeable formation, comprising: a heater configurable to be placed in an opening in the formation, wherein the heater is configurable to provide heat to at least a portion of the formation during use; an oxidizing fluid source configurable to provide an oxidizing fluid to a reaction zone of the formation to generate heat in the reaction zone during use, wherein at least a portion of the reaction zone has been previously heated by the heater during use; a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use; wherein the system is configurable to provide molecular hydrogen to the reaction zone during use; and wherein the system is configurable to allow the generated heat to transfer from the reaction zone to the formation during use.
 5637. The system of claim 5636, wherein the system is configurable to allow the oxidizing fluid to be transported through the reaction zone substantially by diffusion during use.
 5638. The system of claim 5636, wherein the system is configurable to allow the generated heat to transfer from the reaction zone to a pyrolysis zone in the formation during use.
 5639. The system of claim 5636, wherein the system is configurable to allow the generated heat to transfer substantially by conduction from the reaction zone to the formation during use.
 5640. The system of claim 5636, wherein the flow of oxidizing fluid can be controlled along at least a segment of the conduit such that a temperature can be controlled along at least a segment of the conduit during use.
 5641. The system of claim 5636, wherein a flow of oxidizing fluid can be controlled along at least a segment of the conduit such that a heating rate in at least a section of the formation can be controlled.
 5642. The system of claim 5636, wherein the oxidizing fluid is configurable to move through the reaction zone substantially by diffusion during use, wherein a rate of diffusion can controlled by a temperature of the reaction zone.
 5643. The system of claim 5636, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening during use.
 5644. The system of claim 5636, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled during use.
 5645. The system of claim 5636, wherein the conduit comprises a first conduit and a second conduit, wherein the second conduit is configurable to remove an oxidation product during use.
 5646. The system of claim 5636, wherein the oxidizing fluid is substantially inhibited from flowing from the reaction zone into a surrounding portion of the formation.
 5647. The system of claim 5636, wherein at least the portion of the formation extends radially from the opening a distance of less than approximately 3 m.
 5648. The system of claim 5636, wherein the reaction zone extends radially from the opening a distance of less than approximately 3 m.
 5649. The system of claim 5636, wherein the system is configurable to allow transferred heat to pyrolyze at least some hydrocarbons in a pyrolysis zone of the formation.
 5650. The system of claim 5636, wherein the heater is configured to be placed in an opening in the formation and wherein the heater is configured to provide heat to at least a portion of the formation during use.
 5651. The system of claim 5636, wherein the conduit is configured to be placed in the opening to provide at least some of the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use, and wherein the flow of at least some of the oxidizing fluid can be controlled along at least a segment of the first conduit.
 5652. The system of claim 5636, wherein the system is configured to allow heat to transfer from the reaction zone to the formation during use.
 5653. The system of claim 5636, wherein the heater is configured to be placed in an opening in the formation and wherein the heater is configured to provide heat to at least a portion of the formation during use.
 5654. The system of claim 5636, wherein the conduit is configured to be placed in the opening and wherein the conduit is configured to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use.
 5655. The system of claim 5636, wherein the flow of oxidizing fluid can be controlled along at least a segment of the conduit.
 5656. The system of claim 5636, wherein the system is configured to allow heat to transfer from the reaction zone to the formation during use.
 5657. The system of claim 5636, wherein at least some of the provided hydrogen is produced in the pyrolysis zone during use.
 5658. The system of claim 5636, wherein at least some of the provided hydrogen is produced in the reaction zone during use.
 5659. The system of claim 5636, wherein at least some of the provided hydrogen is produced in at least the heated portion of the formation during use.
 5660. The system of claim 5636, wherein the system is configurable to provide hydrogen to the reaction zone during use such that production of carbon dioxide in the reaction zone is inhibited.
 5661. An in situ method for heating a relatively permeable formation, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing fluid to react with at least a portion of the hydrocarbons in the reaction zone to generate heat in the reaction zone; providing molecular hydrogen to the reaction zone; and transferring the generated heat from the reaction zone to a pyrolysis zone in the formation.
 5662. The method of claim 5661, further comprising producing the molecular hydrogen in the pyrolysis zone.
 5663. The method of claim 5661, further comprising producing the molecular hydrogen in the reaction zone.
 5664. The method of claim 5661, further comprising producing the molecular hydrogen in at least the heated portion of the formation.
 5665. The method of claim 5661, further comprising inhibiting production of carbon dioxide in the reaction zone.
 5666. The method of claim 5661, further comprising allowing the oxidizing fluid to transfer through the reaction zone substantially by diffusion.
 5667. The method of claim 5661, further comprising allowing the oxidizing fluid to transfer through the reaction zone by diffusion, wherein a rate of diffusion is controlled by a temperature of the reaction zone.
 5668. The method of claim 5661, wherein at least some of the generated heat transfers to the pyrolysis zone substantially by con duct ion.
 5669. The method of claim 5661, further comprising controlling a flow of the oxidizing fluid along at least a segment reaction zone such that a temperature is controlled along at least a segment of the reaction zone.
 5670. The method of claim 5661, further comprising controlling a flow of the oxidizing fluid along at least a segment of the reaction zone such that a heating rate is controlled along at least a segment of the reaction zone.
 5671. The method of claim 5661, further comprising allowing at least some oxidizing fluid to flow into the formation through orifices in a conduit placed in an opening in the formation.
 5672. The method of claim 5661, further comprising controlling a flow of the oxidizing fluid into the formation using critical flow orifices on a conduit placed in the opening such that a rate of oxidation is controlled.
 5673. The method of claim 5661, further comprising controlling a flow of the oxidizing fluid into the formation with a spacing of critical flow orifices on a conduit placed in an opening in the formation.
 5674. The method of claim 5661, further comprising controlling a flow of the oxidizing fluid with a diameter of critical flow orifices in a conduit placed in an opening in the formation.
 5675. The method of claim 5661, further comprising increasing a volume of the reaction zone, and increasing the flow of the oxidizing fluid to the reaction zone such that a rate of oxidation within the reaction zone is substantially constant over time.
 5676. The method of claim 5661, wherein a conduit is placed in an opening in the formation, and further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.
 5677. The method of claim 5661, further comprising removing an oxidation product from the formation through a conduit placed in an opening in the formation.
 5678. The method of claim 5661, further comprising removing an oxidation product from the formation through a conduit placed in an opening in the formation and inhibiting the oxidation product from flowing into a surrounding portion of the formation beyond the reaction zone.
 5679. The method of claim 5661, further comprising inhibiting the oxidizing fluid from flowing into a surrounding portion of the formation beyond the reaction zone.
 5680. The method of claim 5661, further comprising removing at least some water from the formation prior to heating the portion.
 5681. The method of claim 5661, further comprising providing additional heat to the formation from an electric heater placed in the opening.
 5682. The method of claim 5661, further comprising providing additional heat to the formation from an electric heater placed in the opening and continuously oxidizing at least a portion of the hydrocarbons in the reaction zone.
 5683. The method of claim 5661, further comprising providing additional heat to the formation from an electric heater placed in an opening in the formation and maintaining a constant heat rate within the pyrolysis zone.
 5684. The method of claim 5661, further comprising providing additional heat to the formation from an electric heater placed in the opening such that the oxidation of at least a portion of the hydrocarbons does not burn out.
 5685. The method of claim 5661, further comprising removing oxidation products from the formation and generating electricity using at least some oxidation products removed from the formation.
 5686. The method of claim 5661, further comprising removing oxidation products from the formation and using at least some oxidation products removed from the formation in an air compressor.
 5687. The method of claim 5661, further comprising increasing a flow of the oxidizing fluid in the reaction zone to accommodate an increase in a volume of the reaction zone over time.
 5688. The method of claim 5661, further comprising increasing a volume of the reaction zone such that an amount of heat provided to the formation increases.
 5689. The method of claim 5661, further comprising assessing a temperature in or proximate the opening, and controlling the flow of oxidizing fluid as a function of the assessed temperature.
 5690. The method of claim 5661, further comprising assessing a temperature in or proximate the opening, and increasing the flow of oxidizing fluid as the assessed temperature decreases.
 5691. The method of claim 5661, further comprising controlling the flow of oxidizing fluid to maintain a temperature in or proximate the opening at a temperature less than a pre-selected temperature.
 5692. A system configurable to heat a relatively permeable formation, comprising: a heater configurable to be placed in an opening in the formation, wherein the heater is configurable to provide heat to at least a portion of the formation during use; an oxidizing fluid source, wherein an oxidizing fluid is selected to oxidize at least some hydrocarbons at a reaction zone during use such that heat is generated in the reaction zone; a first conduit configurable to be placed in the opening, wherein the first conduit is configurable to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use; and; a second conduit configurable to be placed in the opening, wherein the second conduit is configurable to remove a product of oxidation from the opening during use; and wherein the system is configurable to allow the generated heat to transfer from the reaction zone to the formation during use.
 5693. The system of claim 5692, wherein the second conduit is configurable to control the concentration of oxygen in the opening during use such that the concentration of oxygen in the opening is substantially constant in the opening.
 5694. The system of claim 5692, wherein the second conduit comprises orifices, and wherein the second conduit comprises a greater concentration of orifices towards an upper end of the second conduit.
 5695. The system of claim 5692, wherein the first conduit comprises orifices that direct oxidizing fluid in a direction substantially opposite the second conduit.
 5696. The system of claim 5692, wherein the second conduit comprises orifices that remove the oxidation product from a direction substantially opposite the first conduit.
 5697. The system of claim 5692, wherein the second conduit is configurable to remove a product of oxidation from the opening during use such that the reaction zone comprises a substantially uniform temperature profile.
 5698. The system of claim 5692, wherein a flow of the oxidizing fluid can be varied along a portion of a length of the first conduit.
 5699. The system of claim 5692, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.
 5700. The system of claim 5692, wherein the system is configurable to allow heat to transfer from the reaction zone to a pyrolysis zone in the formation during use.
 5701. The system of claim 5692, wherein the system is configurable to allow heat to transfer substantially by conduction from the reaction zone to the formation during use.
 5702. The system of claim 5692, wherein a flow of oxidizing fluid can be controlled along at least a portion of a length of the first conduit such that a temperature can be controlled along at least a portion of the length of the first conduit during use.
 5703. The system of claim 5692, wherein a flow of oxidizing fluid can be controlled along at least a portion of the length of the first conduit such that a heating rate in at least a portion of the formation can be controlled.
 5704. The system of claim 5692, wherein the oxidizing fluid is configurable to generate heat in the reaction zone during use such that the oxidizing fluid is transported through the reaction zone during use substantially by diffusion, wherein a rate of diffusion can controlled by a temperature of the reaction zone.
 5705. The system of claim 5692, wherein the first conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening during use.
 5706. The system of claim 5692, wherein the first conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled during use.
 5707. The system of claim 5692, wherein the second conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid in the first conduit during use.
 5708. The system of claim 5692, wherein a pressure of the oxidizing fluid in the first conduit and a pressure of the oxidation product in the second conduit are controlled during use such that a concentration of the oxidizing fluid in along the length of the conduit is substantially uniform.
 5709. The system of claim 5692, wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone during use.
 5710. The system of claim 5692, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone during use.
 5711. The system of claim 5692, wherein the portion of the formation extends radially from the opening a distance of less than approximately 3 m.
 5712. The system of claim 5692, wherein the reaction zone extends radially from the opening a distance of less than approximately 3 m.
 5713. The system of claim 5692, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.
 5714. The system of claim 5692, wherein the heater is configured to be placed in an opening in the formation and wherein the heater is configured to provide heat to at least a portion of the formation during use.
 5715. The system of claim 5692, wherein the first conduit is configured to be placed in the opening, and wherein the first conduit is configured to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use.
 5716. The system of claim 5692, wherein the flow of oxidizing fluid can be controlled along at least a segment of the first conduit.
 5717. The system of claim 5692, wherein the second conduit is configured to be placed in the opening, and wherein the second conduit is configured to remove a product of oxidation from the opening during use.
 5718. The system of claim 5692, wherein the system is configured to allow heat to transfer from the reaction zone to the formation during use.
 5719. An in situ method for heating a relatively permeable formation, comprising: heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid; providing the oxidizing fluid to a reaction zone in the formation; allowing the oxidizing fluid to react with at least a portion of the hydrocarbons in the reaction zone to generate heat in the reaction zone; removing an oxidation product from the opening; and transferring the generated heat from the reaction zone to the formation.
 5720. The method of claim 5719, further comprising removing the oxidation product such that a concentration of oxygen in the opening is substantially constant in the opening.
 5721. The method of claim 5719, further comprising removing the oxidation product from the opening and maintaining a substantially uniform temperature profile within the reaction zone.
 5722. The method of claim 5719, further comprising transporting the oxidizing fluid through the reaction zone substantially by diffusion.
 5723. The method of claim 5719, further comprising transporting the oxidizing fluid through the reaction zone by diffusion, wherein a rate of diffusion is controlled by a temperature of the reaction zone.
 5724. The method of claim 5719, further comprising allowing heat to transfer from the reaction zone to a pyrolysis zone in the formation.
 5725. The method of claim 5719, further comprising allowing heat to transfer from the reaction zone to the formation substantially by conduction.
 5726. The method of claim 5719, further comprising controlling a flow of the oxidizing fluid along at least a portion of the length of the reaction zone such that a temperature is controlled along at least a portion of the length of the reaction zone.
 5727. The method of claim 5719, further comprising controlling a flow of the oxidizing fluid along at least a portion of the length of the reaction zone such that a heating rate is controlled along at least a portion of the length of the reaction zone.
 5728. The method of claim 5719, further comprising allowing at least a portion of the oxidizing fluid into the opening through orifices of a conduit placed in the opening.
 5729. The method of claim 5719, further comprising controlling a flow of the oxidizing fluid with critical flow orifices in a conduit placed in the opening such that a rate of oxidation is controlled.
 5730. The method of claim 5719, further comprising controlling a flow of the oxidizing fluid with a spacing of critical flow orifices in a conduit placed in the opening.
 5731. The method of claim 5719, further comprising controlling a flow of the oxidizing fluid with a diameter of critical flow orifices in a conduit placed in the opening.
 5732. The method of claim 5719, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.
 5733. The method of claim 5719, wherein a conduit is placed in the opening, and further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.
 5734. The method of claim 5719, further comprising removing an oxidation product from the formation through a conduit placed in the opening.
 5735. The method of claim 5719, further comprising removing an oxidation product from the formation through a conduit placed in the opening and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.
 5736. The method of claim 5719, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.
 5737. The method of claim 5719, further comprising removing water from the formation prior to heating the portion.
 5738. The method of claim 5719, further comprising providing additional heat to the formation from an electric heater placed in the opening.
 5739. The method of claim 5719, further comprising providing additional heat to the formation from an electric heater placed in the opening such that the oxidizing fluid continuously oxidizes at least a portion of the hydrocarbons in the reaction zone.
 5740. The method of claim 5719, further comprising providing additional heat to the formation from an electric heater placed in the opening such that a constant heat rate in the formation is maintained.
 5741. The method of claim 5719, further comprising providing additional heat to the formation from an electric heater placed in the opening such that the oxidation of at least a portion of the hydrocarbons does not burn out.
 5742. The method of claim 5719, further comprising generating electricity using oxidation products removed from the formation.
 5743. The method of claim 5719, further comprising using oxidation products removed from the formation in an air compressor.
 5744. The method of claim 5719, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone over time.
 5745. The method of claim 5719, further comprising increasing the amount of heat provided to the formation by increasing the reaction zone.
 5746. The method of claim 5719, further comprising assessing a temperature in or proximate the opening, and controlling the flow of oxidizing fluid as a function of the assessed temperature.
 5747. The method of claim 5719, further comprising assessing a temperature in or proximate the opening, and increasing the flow of oxidizing fluid as the assessed temperature decreases.
 5748. The method of claim 5719, further comprising controlling the flow of oxidizing fluid to maintain a temperature in or proximate the opening at a temperature less than a pre-selected temperature.
 5749. A method of treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling the heat from the one or more heat sources such that an average temperature within at least a selected section of the formation is less than about 375° C.; producing a mixture from the formation from a production well; and controlling heating in or proximate the production well to produce a selected yield of non-condensable hydrocarbons in the produced mixture.
 5750. The method of claim 5749, further comprising controlling heating in or proximate the production well to produce a selected yield of condensable hydrocarbons in the produced mixture.
 5751. The method of claim 5749, wherein the mixture comprises more than about 50 weight percent non-condensable hydrocarbons.
 5752. The method of claim 5749, wherein the mixture comprises more than about 50 weight percent condensable hydrocarbons.
 5753. The method of claim 5749, wherein the average temperature and a pressure within the formation are controlled such that production of carbon dioxide is substantially inhibited.
 5754. The method of claim 5749, heating in or proximate the production well is controlled such that production of carbon dioxide is substantially inhibited.
 5755. The method of claim 5749, wherein at least a portion of the mixture produced from a first portion of the formation at a lower temperature is recycled into a second portion of the formation at a higher temperature such that production of carbon dioxide is substantially inhibited.
 5756. The method of claim 5749, wherein the mixture comprises a volume ratio of molecular hydrogen to carbon monoxide of about 2 to 1, and wherein producing the mixture is controlled such that the volume ratio is maintained between about 1.8 to 1 and about 2.2 to
 1. 5757. The method of claim 5749, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5758. The method of claim 5749, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5759. The method of claim 5749, wherein at least one heat source comprises a heater.
 5760. A method of treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling the heat from the one or more heat sources such that an average temperature within at least a selected section of the formation is less than about 375° C.; and producing a mixture from the formation.
 5761. The method of claim 5760, removing a fluid from the formation through a production well.
 5762. The method of claim 5760, further comprising removing a liquid through a production well.
 5763. The method of claim 5760, further comprising removing water through a production well.
 5764. The method of claim 5760, further comprising removing a fluid through a production well prior to providing heat to the formation.
 5765. The method of claim 5760, further comprising removing water from the formation through a production well prior to providing heat to the formation.
 5766. The method of claim 5760, further comprising removing the fluid through a production well using a pump.
 5767. The method of claim 5760, further comprising removing a fluid through a conduit.
 5768. The method of claim 5760, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5769. The method of claim 5760, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5770. The method of claim 5760, wherein at least one heat source comprises a heater.
 5771. A method of treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling the heat from the one or more heat sources such that an average temperature within at least a selected section of the formation is less than about 375° C.; measuring a temperature within a wellbore placed in the formation; and producing a mixture from the formation.
 5772. The method of claim 5771, further comprising measuring the temperature using a moveable thermocouple.
 5773. The method of claim 5771, further comprising measuring the temperature using an optical fiber assembly.
 5774. The method of claim 5771, further comprising measuring the temperature within a production well.
 5775. The method of claim 5771, further comprising measuring the temperature within a heater well.
 5776. The method of claim 5771, further comprising measuring the temperature within a monitoring well.
 5777. The method of claim 5771, further comprising providing a pressure wave from a pressure wave source into the wellbore, wherein the wellbore comprises a plurality of discontinuities along a length of the wellbore, measuring a reflection signal of the pressure wave, and using the reflection signal to assess at least one temperature between at least two discontinuities.
 5778. The method of claim 5771, further comprising assessing an average temperature in the formation using one or more temperatures measured within at least one wellbore.
 5779. The method of claim 5771, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5780. The method of claim 5771, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5781. The method of claim 5771, wherein at least one heat source comprises a heater.
 5782. An in situ method of measuring assessing a temperature within a wellbore in a relatively permeable formation, comprising: providing a pressure wave from a pressure wave source into the wellbore, wherein the wellbore comprises a plurality of discontinuities along a length of the wellbore; measuring a reflection signal of the pressure wave; and using the reflection signal to assess at least one temperature between at least two discontinuities.
 5783. The method of claim 5782, wherein the plurality of discontinuities are placed along a length of a conduit placed in the wellbore.
 5784. The method of claim 5783, wherein the pressure wave is propagated through a wall of the conduit.
 5785. The method of claim 5783, wherein the plurality of discontinuities comprises collars placed within the conduit.
 5786. The method of claim 5783, wherein the plurality of discontinuities comprises welds placed within the conduit.
 5787. The method of claim 5782, wherein determining the at least one temperature between at least the two discontinuities comprises relating a velocity of the pressure wave between discontinuities to the at least one temperature.
 5788. The method of claim 5782, further comprising measuring a reference signal of the pressure wave within the wellbore at an ambient temperature.
 5789. The method of claim 5782, further comprising measuring a reference signal of the pressure wave within the wellbore at an ambient temperature, and then determining the at least one temperature between at least the two discontinuities by comparing the measured signal to the reference signal.
 5790. The method of claim 5782, wherein the at least one temperature is a temperature of a gas between at least the two discontinuities.
 5791. The method of claim 5782, wherein the wellbore comprises a production well.
 5792. The method of claim 5782, wherein the wellbore comprises a heater well.
 5793. The method of claim 5782, wherein the wellbore comprises a monitoring well.
 5794. The method of claim 5782, wherein the pressure wave source comprises a solenoid valve.
 5795. The method of claim 5782, wherein the pressure wave source comprises an explosive device.
 5796. The method of claim 5782, wherein the pressure wave source comprises a sound device.
 5797. The method of claim 5782, wherein the pressure wave is propagated through the wellbore.
 5798. The method of claim 5782, wherein the plurality of discontinuities have a spacing between each discontinuity of about 5 m.
 5799. The method of claim 5782, further comprising repeatedly providing the pressure wave into the wellbore at a selected frequency and continuously measuring the reflected signal to increase a signal-to-noise ratio of the reflected signal.
 5800. The method of claim 5782, further comprising providing heat from one or more heat sources to a portion of the formation.
 5801. The method of claim 5782, further comprising pyrolyzing at least some hydrocarbons within a portion of the formation.
 5802. The method of claim 5782, further comprising generating synthesis gas in at least a portion of the formation.
 5803. A method of treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 375° C.; and producing a mixture from the formation through a heater well.
 5804. The method of claim 5803, wherein producing the mixture through the heater well increases a production rate of the mixture from the formation.
 5805. The method of claim 5803, further comprising providing heat using at least 2 heat sources.
 5806. The method of claim 5803, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.
 5807. The method of claim 5803, wherein the one or more heat sources comprise a pattern of heat sources in a formation, and wherein superposition of heat from the pattern of heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.
 5808. The method of claim 5803, wherein heating of a majority of selected section is controlled such that a temperature of the majority of the selected section is less than about 375° C.
 5809. The method of claim 5803, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5810. The method of claim 5803, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5811. The method of claim 5803, wherein at least one heat source comprises a heater.
 5812. A method of treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; wherein heating is provided from at least a first heat source and at least a second heat source, wherein the first heat source has a first heating cost and the second heat source has a second heating cost; controlling a heating rate of at least a portion of the selected section to preferentially use the first heat source when the first heating cost is less than the second heating cost; and controlling the heat from the one or more heat sources to pyrolyze at least some hydrocarbon in the selected section of the formation.
 5813. The method of claim 5812, further comprising controlling the heating rate such that a temperature within at least a majority of the selected section of the formation is less than about 375° C.
 5814. The method of claim 5812, further comprising providing heat using at least 2 heat sources.
 5815. The method of claim 5812, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.
 5816. The method of claim 5812, wherein the one or more heat sources comprise a pattern of heat sources in a formation, and wherein superposition of heat from the pattern of heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.
 5817. The method of claim 5812, further comprising controlling the heating to preferentially use the second heat source when the second heating cost is less than the first heating cost.
 5818. The method of claim 5812, further comprising producing a mixture from the formation.
 5819. The method of claim 5812, wherein heating of a majority of selected section is controlled such that a temperature of the majority of the selected section is less than about 375° C.
 5820. The method of claim 5812, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5821. The method of claim 5812, wherein at least one heat source comprises a heater.
 5822. The method of claim 5812, further comprising producing a mixture from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5823. A method of treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; wherein heating is provided from at least a first heat source and at least a second heat source, wherein the first heat source has a first heating cost and the second heat source has a second heating cost; controlling a heating rate of at least a portion of the selected section such that a cost associated with heating the selected section is minimized; and controlling the heat from the one or more heat sources to pyrolyze at least some hydrocarbon in at least a portion of the selected section of the formation.
 5824. The method of claim 5823, wherein the heating rate is varied within a day depending on a cost associated with heating at various times in the day.
 5825. The method of claim 5823, further comprising controlling the heating rate such that a temperature within at least a majority of the selected section of the formation is less than about 375° C.
 5826. The method of claim 5823, further comprising providing heat using at least 2 heat sources.
 5827. The method of claim 5823, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.
 5828. The method of claim 5823, wherein the one or more heat sources comprise a pattern of heat sources in a formation, and wherein superposition of heat from the pattern of heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.
 5829. The method of claim 5823, further comprising producing a mixture from the formation.
 5830. The method of claim 5823, wherein heating of a majority of selected section is controlled such that a temperature of the majority of the selected section is less than about 375° C.
 5831. The method of claim 5823, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5832. The method of claim 5823, wherein at least one heat source comprises a heater.
 5833. The method of claim 5823, further comprising producing a mixture from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5834. A method for controlling an in situ system of treating a relatively permeable formation, comprising: monitoring at least one acoustic event within the formation using at least one acoustic detector placed within a wellbore in the formation; recording at least one acoustic event with an acoustic monitoring system; analyzing at least one acoustic event to determine at least one property of the formation; and controlling the in situ system based on the analysis of the at least one acoustic event.
 5835. The method of claim 5834, wherein the at least one acoustic event comprises a seismic event.
 5836. The method of claim 5834, wherein the method is continuously operated.
 5837. The method of claim 5834, wherein the acoustic monitoring system comprises a seismic monitoring system.
 5838. The method of claim 5834, further comprising recording the at least one acoustic event with the acoustic monitoring system.
 5839. The method of claim 5834, further comprising monitoring more than one acoustic event simultaneously with the acoustic monitoring system.
 5840. The method of claim 5834, further comprising monitoring the at least one acoustic event at a sampling rate of about at least once every 0.25 milliseconds.
 5841. The method of claim 5834, wherein analyzing the at least one acoustic event comprises interpreting the at least one acoustic event.
 5842. The method of claim 5834, wherein the at least one property of the formation comprises a location of at least one fracture in the formation.
 5843. The method of claim 5834, wherein the at least one property of the formation comprises an extent of at least one fracture in the formation.
 5844. The method of claim 5834, wherein the at least one property of the formation comprises an orientation of at least one fracture in the formation.
 5845. The method of claim 5834, wherein the at least one property of the formation comprises a location and an extent of at least one fracture in the formation.
 5846. The method of claim 5834, wherein controlling the in situ system comprises modifying a temperature of the in situ system.
 5847. The method of claim 5834, wherein controlling the in situ system comprises modifying a pressure of the in situ system.
 5848. The method of claim 5834, wherein the at least one acoustic detector comprises a geophone.
 5849. The method of claim 5834, wherein the at least one acoustic detector comprises a hydrophone.
 5850. The method of claim 5834, further comprising providing heat to at least a portion of the formation.
 5851. The method of claim 5834, further comprising pyrolyzing hydrocarbons within at least a portion of the formation.
 5852. The method of claim 5834, further comprising providing heat from one or more heat sources to a portion of the formation.
 5853. The method of claim 5834, further comprising pyrolyzing at least some hydrocarbons within a portion of the formation.
 5854. The method of claim 5834, further comprising generating synthesis gas in at least a portion of the formation.
 5855. A method of predicting characteristics of a formation fluid produced from an in situ process, wherein the in situ process is used for treating a relatively permeable formation, comprising: determining an isothermal experimental temperature that can be used when treating a sample of the formation, wherein the isothermal experimental temperature is correlated to a selected in situ heating rate for the formation; and treating a sample of the formation at the determined isothermal experimental temperature, wherein the experiment is used to assess at least one product characteristic of the formation fluid produced from the formation for the selected heating rate.
 5856. The method of claim 5855, further comprising determining the at least one product characteristic at a selected pressure.
 5857. The method of claim 5855, further comprising modifying the selected heating rate so that at least one desired product characteristic of the formation fluid is obtained.
 5858. The method of claim 5855, further comprising using a selected well spacing in the formation to determine the selected heating rate.
 5859. The method of claim 5855, further comprising using a selected heat input into the formation to determine the selected heating rate.
 5860. The method of claim 5855, further comprising using at least one property of the formation to determine the selected heating rate.
 5861. The method of claim 5855, further comprising selecting a desired heating rate such that at least one desired product characteristic of the formation fluid is obtained.
 5862. The method of claim 5855, further comprising determining the isothermal temperature using an equation that estimates a temperature in which a selected amount of hydrocarbons in the formation are converted.
 5863. The method of claim 5855, wherein the selected heating rate is less than about 1° C. per day.
 5864. The method of claim 5855, wherein the sample is treated in an insulated vessel.
 5865. The method of claim 5855, wherein at least one assessed produced characteristic is used to design at least one surface processing system, wherein the surface processing system is used to treat produced fluids on the surface.
 5866. The method of claim 5855, wherein the formation is treated using a heating rate of about the selected heating rate.
 5867. The method of claim 5855, further comprising using at least one product characteristic to assess a pressure to be maintained in the formation during treatment.
 5868. A method of treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; adding hydrogen to the selected section after a temperature of the selected section is at least about 270° C.; and producing a mixture from the formation.
 5869. The method of claim 5868, wherein the temperature of the selected section is at least about 290° C.
 5870. The method of claim 5868, wherein the temperature of the selected section is at least about 320° C.
 5871. The method of claim 5868, wherein the temperature of the selected section is less than about 375° C.
 5872. The method of claim 5868, wherein the temperature of the selected section is less than about 400° C.
 5873. The method of claim 5868, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5874. The method of claim 5868, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5875. The method of claim 5868, wherein at least one heat source comprises a heater.
 5876. A method of treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and controlling a temperature of a majority of the selected section by selectively adding hydrogen to the formation.
 5877. The method of claim 5876, further comprising controlling the temperature such that the temperature is less than about 375° C.
 5878. The method of claim 5876, further comprising controlling the temperature such that the temperature is less than about 400° C.
 5879. The method of claim 5876, further comprising controlling a heating rate such that the temperature is less than about 375° C.
 5880. The method of claim 5876, wherein the one or more heat sources comprise a pattern of heat sources in a formation, and wherein superposition of heat from the pattern of heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.
 5881. The method of claim 5876, further comprising producing a mixture from the formation.
 5882. The method of claim 5876, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5883. The method of claim 5876, further comprising producing a mixture from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5884. The method of claim 5876, wherein at least one heat source comprises a heater.
 5885. A method of treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least the portion to a selected section of the formation; and producing fluids from the formation wherein at least a portion of the produced fluids have been heated by the heat provided by one or more of the heat sources, and wherein at least a portion of the produced fluids are produced at a temperature greater than about 200° C.
 5886. The method of claim 5885, wherein at least a portion of the produced fluids are produced at a temperature greater than about 250° C.
 5887. The method of claim 5885, wherein at least a portion of the produced fluids are produced at a temperature greater than about 300° C.
 5888. The method of claim 5885, further comprising varying the heat provided to the one or more heat sources to vary heat in at least a portion of the produced fluids.
 5889. The method of claim 5885, wherein the produced fluids are produced from a well comprising at least one of the heat sources, and further comprising varying the heat provided to the one or more heat sources to vary heat in at least a portion of the produced fluids.
 5890. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a hydrotreating unit.
 5891. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a hydrotreating unit, and further comprising varying the heat provided to the one or more heat sources to vary heat in at least a portion of the produced fluids provided to the hydrotreating unit.
 5892. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a hydrotreating unit, and using heat in the produced fluids when hydrotreating at least a portion of the produced fluids.
 5893. The method of claim 5885, further comprising providing at east a portion of the produced fluids to a hydrotreating unit, and hydrotreating at least a portion of the produced fluids without using a surface heater to heat produced fluids.
 5894. The method of claim 5885, further comprising: providing at least a portion of the produced fluids to a hydrotreating unit; and hydrotreating at least a portion of the produced fluids; wherein at least 50% of heat used for hydrotreating is provided by heat in the produced fluids.
 5895. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a hydrotreating unit, wherein at least a portion of the produced fluids are provided to the hydrotreating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.
 5896. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a hydrotreating unit, wherein at least a portion of the produced fluids are provided to the hydrotreating unit via a heated conduit.
 5897. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a hydrotreating unit wherein the produced fluids are produced at a wellhead, and wherein at least a portion of the produced fluids are provided to the hydrotreating unit at a temperature that is within about 50° C. of the temperature of the produced fluids at the wellhead.
 5898. The method of claim 5885, further comprising hydrotreating at least a portion of the produced fluids such that the volume of hydrotreated produced fluids is about 4% greater than a volume of the produced fluids.
 5899. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a hydrotreating unit wherein the produced fluids comprise molecular hydrogen, and using the molecular hydrogen in the produced fluids to hydrotreat at least a portion of the produced fluids.
 5900. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a hydrotreating unit wherein the produced fluids comprise molecular hydrogen, hydrotreating at least a portion of the produced fluids, and wherein at least 50% of molecular hydrogen used for hydrotreating is provided by the molecular hydrogen in the produced fluids.
 5901. The method of claim 5885, wherein the produced fluids comprise molecular hydrogen, separating at least a portion of the molecular hydrogen from the produced fluids, and providing at least a portion of the separated molecular hydrogen to a surface treatment unit.
 5902. The method of claim 5885, wherein the produced fluids comprise molecular hydrogen, separating at least a portion of the molecular hydrogen from the produced fluids, and providing at least a portion of the separated molecular hydrogen to an in situ treatment area.
 5903. The method of claim 5885, further comprising providing a portion of the produced fluids to an olefin generating unit.
 5904. The method of claim 5885, further comprising providing a portion of the produced fluids to a steam cracking unit.
 5905. The method of claim 5885, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and further comprising varying heat provided to the one or more heat sources to vary the heat in at least a portion of the produced fluids provided to the olefin generating unit.
 5906. The method of claim 5885, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using heat in the produced fluids when generating olefins from at least a portion of the produced fluids.
 5907. The method of claim 5885, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and generating olefins from at least a portion of the produced fluids without using a surface heater to heat produced fluids.
 5908. The method of claim 5885, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and generating olefins from at least a portion of the produced fluids, and wherein at least 50% of the heat used for generating olefins is provided by heat in the produced fluids.
 5909. The method of claim 5885, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.
 5910. The method of claim 5885, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via a heated conduit.
 5911. The method of claim 5885, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein the produced fluids are produced at a wellhead, and wherein at least a portion of the produced fluids are provided to the olefin generating unit at a temperature that is within about 50° C. of the temperature of the produced fluids at the wellhead.
 5912. The method of claim 5885, further comprising removing heat from the produced fluids in a heat exchanger.
 5913. The method of claim 5885, further comprising separating the produced fluids into two or more streams comprising at least a synthetic condensate stream, and a non-condensable fluid stream.
 5914. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into two or more streams.
 5915. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into two or more streams, and further comprising separating at least one of such streams into two or more substreams.
 5916. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into three or more streams, and wherein such streams comprise at least a top stream, a bottom stream, and a middle stream.
 5917. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit, and further comprising varying heat provided to the one or more heat sources to vary the heat in at least a portion of the produced fluids provided to the separating unit.
 5918. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit, and using heat in the produced fluids when separating at least a portion of the produced fluids.
 5919. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids without using a surface heater to heat produced fluids.
 5920. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids, and wherein at least 50% of the heat used for separating is provided by heat in the produced fluids.
 5921. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit wherein at least a portion of the produced fluids are provided to the separating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.
 5922. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit wherein at least a portion of the produced fluids are provided to the separating unit via a heated conduit.
 5923. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit wherein the produced fluids are produced at a wellhead, and wherein at least a portion of the produced fluids are provided to the separating unit at a temperature that is within about 50° C. of the temperature of the produced fluids at the wellhead.
 5924. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into four or more streams, and wherein such streams comprise at least a top stream, a bottoms stream, and at least two middle streams wherein one of the middle streams is heavier than the other middle stream.
 5925. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into five or more streams, and wherein such streams comprise at least a top stream, a bottoms stream, a naphtha stream, diesel stream, and a jet fuel stream.
 5926. The method of claim 5885, further comprising providing at least a portion of the produced fluids to a distillation column, and using heat in the produced fluids when distilling at least a portion of the produced fluids.
 5927. The method of claim 5885, wherein the produced fluids comprise pyrolyzation fluids.
 5928. The method of claim 5885, wherein the produced fluids comprise carbon dioxide, and further comprising separating at least a portion of the carbon dioxide from the produced fluids.
 5929. The method of claim 5885, wherein the produced fluids comprise carbon dioxide, and further comprising separating at least a portion of the carbon dioxide from the produced fluids, and utilizing at least some carbon dioxide in one or more treatment processes.
 5930. The method of claim 5885, wherein the produced fluids comprise molecular hydrogen and wherein the molecular hydrogen is used when treating the produced fluids.
 5931. The method of claim 5885, wherein the produced fluids comprise steam and wherein the steam is used when treating the produced fluids.
 5932. The method of claim 5885, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5933. The method of claim 5885, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5934. The method of claim 5885, wherein at least one heat source comprises a heater.
 5935. A method of converting formation fluids into olefins, comprising: converting formation fluids into olefins, wherein the formation fluids are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from one or more heat sources to a selected section of the formation such that at least some hydrocarbons in the formation are pyrolyzed; and producing formation fluids from the formation.
 5936. The method of claim 5935 wherein the produced fluids comprise steam.
 5937. The method of claim 5935 wherein the produced fluids comprise steam and wherein the steam in the produced fluids comprises at least a portion of steam used in the olefin generating unit.
 5938. The method of claim 5935, further comprising providing at least a portion of the produced fluids to an olefin generating unit.
 5939. The method of claim 5935, further comprising providing at least a portion of the produced fluids to a steam cracking unit.
 5940. The method of claim 5935 wherein olefins comprise ethylene.
 5941. The method of claim 5935 wherein olefins comprise propylene.
 5942. The method of claim 5935, further comprising separating liquids from the produced fluids, and then separating olefin generating compounds from the produced fluids, and then providing at least a portion of the olefin generating compounds to an olefin generating unit.
 5943. The method of claim 5935 wherein the produced fluids comprise molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids prior to using the produced fluids to produce olefins.
 5944. The method of claim 5935 wherein the produced fluids comprise molecular hydrogen, and further comprising separating at least a portion of the molecular hydrogen from the produced fluids, and utilizing at least a portion of the separated molecular hydrogen in one or more treatment processes.
 5945. The method of claim 5935 wherein the produced fluids comprise molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids using a hydrogen removal unit prior to using the produced fluids to produce olefins.
 5946. The method of claim 5935 wherein the produced fluids comprises molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids using a membrane prior to using the produced fluids to produce olefins.
 5947. The method of claim 5935, further comprising generating molecular hydrogen during production of olefins, and providing at least a portion of the generated molecular hydrogen to one or more hydrotreating units.
 5948. The method of claim 5935, further comprising generating molecular hydrogen during production of olefins, and providing at least a portion of the generated molecular hydrogen to an in situ treatment area.
 5949. The method of claim 5935, further comprising generating molecular hydrogen during production of olefins, and providing at least a portion of the generated molecular hydrogen to one or more fuel cells.
 5950. The method of claim 5935, further comprising generating molecular hydrogen during production of olefins, and using at least a portion of the generated molecular hydrogen to hydrotreat pyrolysis liquids generated in the olefin generation plant.
 5951. The method of claim 5935 wherein the produced fluids are at least 200° C., and further comprising using heat in the produced fluids to produce olefins.
 5952. The method of claim 5935, further comprising providing at least a portion of the produced fluids to a hydrotreating unit wherein the produced fluids are produced at a wellhead, and wherein at least a portion of the produced fluids are provided to the olefins generating unit at a temperature that is within about 50° C. of the temperature of the produced fluids at the wellhead.
 5953. The method of claim 5935 wherein the produced fluids can be used to make olefins without substantial hydrotreating of the produced fluids.
 5954. The method of claim 5935, further comprising separating liquids from the produced fluids, and then using at least a portion of the produced fluids to produce olefins.
 5955. The method of claim 5935, further comprising controlling a fluid pressure within at least a portion of the formation to enhance production of olefin generating compounds in the produced fluids.
 5956. The method of claim 5935, further comprising controlling a temperature within at least a portion of the formation to enhance production of olefin generating compounds in the produced fluids.
 5957. The method of claim 5935, further comprising controlling a temperature profile within at least a portion of the formation to enhance production of olefin generating compounds in the produced fluids.
 5958. The method of claim 5935, further comprising controlling a heating rate within at least a portion of the formation to enhance production of olefin generating compounds in the produced fluids.
 5959. The method of claim 5935, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and further comprising varying heat provided to the one or more heat sources to vary the heat in at least a portion of the produced fluids provided to the olefin generating unit.
 5960. The method of claim 5935, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using heat in the produced fluids when generating olefins from at least a portion of the produced fluids.
 5961. The method of claim 5935 wherein the produced fluids comprise steam, and further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using steam in the produced fluids when generating olefins from at least a portion of the produced fluids.
 5962. The method of claim 5935 wherein the produced fluids comprise steam, and further comprising providing at least a portion of the produced fluids to an olefin generating unit, generating olefins from at least a portion of the produced fluids, and wherein at least some steam used for generating olefins is provided by the steam in the produced fluids.
 5963. The method of claim 5935, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.
 5964. The method of claim 5935, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via a heated conduit.
 5965. The method of claim 5935, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise a naphtha fraction, and further comprising providing the naphtha fraction to an olefin generating unit.
 5966. The method of claim 5935, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise a olefin generating fraction wherein the olefin generating fraction comprises hydrocarbons having a carbon number greater than about 1 and a carbon number less than about 8, and further comprising providing the olefin generating fraction to a olefin generating unit.
 5967. The method of claim 5935, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise an olefin generating fraction wherein the olefin generating fraction comprises hydrocarbons having a carbon number greater than about 1 and a carbon number less than about 6, and further comprising providing the olefin generating fraction to a olefin generating unit.
 5968. The method of claim 5935, further comprising providing at least the portion of the produced fluids to a component removal unit such that at least one component stream and a reduced component fluid stream are formed, and then providing the reduced component fluid stream to an olefin generating unit.
 5969. The method of claim 5968, wherein the component comprises a metal.
 5970. The method of claim 5968, wherein the component comprises arsenic.
 5971. The method of claim 5968, wherein the component comprises mercury.
 5972. The method of claim 5968, wherein the component comprises lead.
 5973. The method of claim 5935, further comprising providing at least the portion of the produced fluids to a component removal unit such that at least one component stream and a reduced component fluid stream are formed, then providing the reduced component fluid stream to a molecular hydrogen separating unit such that a molecular hydrogen stream and a reduced hydrogen fluid stream are formed, then providing the molecular hydrogen stream to a hydrotreating unit, and then providing the reduced hydrogen produced fluid stream to an olefin generating unit.
 5974. The method of claim 5935 wherein the produced fluids comprise molecular hydrogen and wherein the molecular hydrogen is used when treating the produced fluids.
 5975. The method of claim 5935 wherein the produced fluids comprise steam and wherein the steam is used when treating the produced fluids.
 5976. The method of claim 5935, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using heat in the produced fluids when generating olefins from at least a portion of the produced fluids.
 5977. The method of claim 5935 wherein the produced fluids comprise steam, and further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using steam in the produced fluids when generating olefins from at least a portion of the produced fluids.
 5978. The method of claim 5935, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.
 5979. The method of claim 5935, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via a heated conduit.
 5980. The method of claim 5935, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 5981. The method of claim 5935, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 5982. The method of claim 5935, wherein at least one heat source comprises a heater.
 5983. A method of separating olefins from fluids produced from a relatively permeable formation, comprising: separating olefins from the produced fluids, wherein the produced fluids are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing fluids from the formation wherein the produced fluids comprise olefins.
 5984. The method of claim 5983 wherein olefins comprise ethylene.
 5985. The method of claim 5983 wherein olefins comprise propylene.
 5986. The method of claim 5983, further comprising separating liquids from the produced fluids.
 5987. The method of claim 5983 wherein the produced fluids comprise molecular hydrogen, and further comprising separating at least a portion of the molecular hydrogen from the produced fluids, and utilizing at least a portion of the separated molecular hydrogen in one or more treatment processes.
 5988. The method of claim 5983 wherein the produced fluids comprise molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids using a hydrogen removal unit.
 5989. The method of claim 5983 wherein the produced fluids comprises molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids using a membrane.
 5990. The method of claim 5983, further comprising controlling a fluid pressure within at least a portion of the formation to enhance production of olefins in the produced fluids.
 5991. The method of claim 5983, further comprising controlling a temperature within at least a portion of the formation to enhance production of olefins in the produced fluids.
 5992. The method of claim 5983, further comprising controlling a temperature profile within at least a portion of the formation to enhance production of olefins in the produced fluids.
 5993. The method of claim 5983, further comprising controlling a heating rate within at least a portion of the formation to enhance production of olefins in the produced fluids.
 5994. The method of claim 5983, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and further comprising varying heat provided to the one or more heat sources to vary the heat in at least a portion of the produced fluids provided to the olefin generating unit.
 5995. The method of claim 5983, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using heat in the produced fluids when generating olefins from at least a portion of the produced fluids.
 5996. The method of claim 5983 wherein the produced fluids comprise steam, and further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using steam in the produced fluids when generating olefins from at least a portion of the produced fluids.
 5997. The method of claim 5983, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.
 5998. The method of claim 5983, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via a heated conduit.
 5999. The method of claim 5983, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise a naphtha fraction, and further comprising providing the naphtha fraction to an olefin generating unit.
 6000. The method of claim 5983, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise a olefin generating fraction wherein the olefin generating fraction comprises hydrocarbons having a carbon number greater than about 1 and a carbon number less than about 8, and further comprising providing the olefin generating fraction to a olefin generating unit.
 6001. The method of claim 5983, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise an olefin generating fraction wherein the olefin generating fraction comprises hydrocarbons having a carbon number greater than about 1 and a carbon number less than about 6, and further comprising providing the olefin generating fraction to a olefin generating unit.
 6002. The method of claim 5983, further comprising providing at least the portion of the produced fluids to a component removal unit such that at least one component stream and a reduced component fluid stream are formed, and then providing the reduced component fluid stream to an olefin generating unit.
 6003. The method of claim 6002 wherein the component comprises a metal.
 6004. The method of claim 6002 wherein the component comprises arsenic.
 6005. The method of claim 6002 wherein the component comprises mercury.
 6006. The method of claim 6002 wherein the component comprises lead.
 6007. The method of claim 5983, further comprising providing at least the portion of the produced fluids to a component removal unit such that at least one component stream and a reduced component fluid stream are formed, then providing the reduced component fluid stream to a molecular hydrogen separating unit such that a molecular hydrogen stream and a reduced hydrogen fluid stream are formed, then providing the molecular hydrogen stream to a hydrotreating unit, and then providing the reduced hydrogen produced fluid stream to an olefin generating unit.
 6008. The method of claim 5983, further comprising controlling a temperature gradient within at least a portion of the formation to enhance production of olefins in the produced fluids.
 6009. The method of claim 5983, further comprising controlling a fluid pressure within at least a portion of the formation to enhance production of olefins in the produced fluids.
 6010. The method of claim 5983, further comprising controlling a temperature within at least a portion of the formation to enhance production of olefins in the produced fluids.
 6011. The method of claim 5983, further comprising controlling a heating rate within at least a portion of the formation to enhance production of olefins in the produced fluids.
 6012. The method of claim 5983, further comprising separating the olefins from the produced fluids such that an amount of molecular hydrogen utilized in one or more downstream hydrotreating units decreases.
 6013. The method of claim 5983, further comprising removing at least a portion of the olefins prior to hydrotreating produced fluids.
 6014. A method of enhancing BTEX compounds production from a relatively permeable formation, comprising: controlling at least one condition within at least a portion of the formation to enhance production of BTEX compounds in formation fluid, wherein the formation fluid is obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing formation fluids from the formation.
 6015. The method of claim 6014, further comprising separating at least a portion of the BTEX compounds from the produced fluids.
 6016. The method of claim 6014, further comprising separating at least a portion of the BTEX compounds from the produced fluids via solvent extraction.
 6017. The method of claim 6014, further comprising separating at least a portion of the BTEX compounds from the produced fluids via distillation.
 6018. The method of claim 6014, further comprising separating at least a portion of the BTEX compounds from the produced fluids via condensation.
 6019. The method of claim 6014, further comprising separating at least a portion of the BTEX compounds from the produced fluids such that an amount of molecular hydrogen utilized in one or more downstream hydrotreating units decreases.
 6020. The method of claim 6014, wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.
 6021. The method of claim 6014, wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.
 6022. The method of claim 6014, wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.
 6023. The method of claim 6014, wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.
 6024. The method of claim 6014, further comprising removing at least a portion of the BTEX compounds prior to hydrotreating produced fluids.
 6025. The method of claim 6014, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6026. The method of claim 6014, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6027. The method of claim 6014, wherein at least one heat source comprises a heater.
 6028. A method of separating BTEX compounds from formation fluid from a relatively permeable formation, comprising: separating at least a portion of the BTEX compounds from the formation fluid wherein the formation fluid is obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing fluids from the formation wherein the produced fluids comprise BTEX compounds.
 6029. The method of claim 6028, further comprising hydrotreating at least a portion of the produced fluids after the BTEX compounds have been separated from same.
 6030. The method of claim 6028 wherein separating at least a portion of the BTEX compounds from the produced fluids comprises extracting at least the portion of the BTEX compounds from the produced fluids via solvent extraction.
 6031. The method of claim 6028 wherein separating at least a portion of the BTEX compounds from the produced fluids comprises distilling at least the portion of the BTEX compounds from the produced fluids.
 6032. The method of claim 6028 wherein separating at least a portion of the BTEX compounds from the produced fluids comprises condensing at least the portion of the BTEX compounds from the produced fluids.
 6033. The method of claim 6028 wherein separating at least a portion of the BTEX compounds from the produced fluids such that an amount of molecular hydrogen utilized in one or more downstream hydrotreating units decreases.
 6034. The method of claim 6028, further comprising controlling a fluid pressure within at least a portion of the formation.
 6035. The method of claim 6028, further comprising controlling a temperature gradient within at least a portion of the formation.
 6036. The method of claim 6028, further comprising controlling a temperature within at least a portion of the formation.
 6037. The method of claim 6028, further comprising controlling a heating rate within at least a portion of the formation.
 6038. The method of claim 6028 wherein separating at least the portion of BTEX compounds from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least the portion of BTEX compounds from the naphtha fraction.
 6039. The method of claim 6028, wherein separating at least the portion of BTEX compounds from the produced fluids, further comprises removing a BTEX fraction from the produced fluids, and separating at some BTEX compounds from the BTEX fraction.
 6040. The method of claim 6028, wherein separating at least the portion of BTEX compounds from the produced fluids decreases an amount of molecular hydrogen utilized in one or more downstream hydrotreating units.
 6041. A method of in situ converting at least a portion of formation fluid into BTEX compounds, comprising: in situ converting at least the portion of the formation fluid into BTEX compounds, wherein the formation fluid are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation such that at least some hydrocarbons in the formation are pyrolyzed; and producing formation fluid from the formation.
 6042. The method of claim 6041, further comprising providing at least a portion of the formation fluid to an BTEX generating unit.
 6043. The method of claim 6041, further comprising providing at least a portion of the formation fluid to a catalytic reforming unit.
 6044. The method of claim 6041, further comprising hydrotreating at least some of the formation fluid, and then separating the hydrotreated mixture into one more streams comprising a naphtha stream, and then reforming at least a portion the naphtha stream to form a reformate comprising BTEX compounds, and then separating at least a portion of the BTEX compounds from the reformate.
 6045. The method of claim 6041, further comprising hydrotreating at least some of the formation fluid, and then separating the hydrotreated mixture into one more streams comprising a naphtha stream, and then reforming at least a portion the naphtha stream to form a molecular hydrogen stream and a reformate comprising BTEX compounds, and then separating at least a portion of the BTEX compounds from the reformate, and then utilizing the molecular hydrogen stream to hydrotreat at least some of the formation fluid.
 6046. The method of claim 6041, further comprising hydrotreating the formation fluid, and then separating the hydrotreated formation fluid into one more streams comprising a naphtha stream, and then reforming at least a portion the naphtha stream to form a reformate comprising BTEX compounds, and then separating at least a portion of the reformate into two or more streams comprising a raffinate and a BTEX stream.
 6047. The method of claim 6041 wherein the formation fluid is at least 200° C., and further comprising using heat in the formation fluid to hydrotreat at least a portion of the formation fluid.
 6048. The method of claim 6041, further comprising separating at least a portion of the formation fluid into one or more fractions wherein the one or more fractions comprise a naphtha fraction, and further comprising providing the naphtha fraction to a catalytic reforming unit.
 6049. The method of claim 6041, further comprising separating at least a portion of the formation fluid into one or more fractions wherein the one or more fractions comprise a BTEX compound generating fraction wherein the BTEX compound generating fraction comprises hydrocarbons, and further comprising providing the BTEX compound generating fraction to a catalytic reforming unit.
 6050. The method of claim 6041, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6051. The method of claim 6041, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6052. The method of claim 6041, wherein at least one heat source comprises a heater.
 6053. A method of enhancing naphthalene production from a relatively permeable formation, comprising: controlling at least one condition within at least a portion of the formation to enhance production of naphthalene in formation fluid, wherein the formation fluid is obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing formation fluids from the formation.
 6054. The method of claim 6053, further comprising separating at least a portion of the naphthalene from the produced fluids.
 6055. The method of claim 6053, wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.
 6056. The method of claim 6053, wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.
 6057. The method of claim 6053, wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.
 6058. The method of claim 6053, wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.
 6059. The method of claim 6053, further comprising separating the produced fluids into one or more fractions using distillation.
 6060. The method of claim 6053, further comprising separating the produced fluids into one or more fractions using condensation.
 6061. The method of claim 6053, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some naphthalene from the heart cut.
 6062. The method of claim 6053, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a naphthalene fraction, and further comprising providing the naphthalene fraction to an extraction unit, and separating at least some naphthalene from the naphthalene fraction.
 6063. The method of claim 6053, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6064. The method of claim 6053, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6065. The method of claim 6053, wherein at least one heat source comprises a heater.
 6066. A method of separating naphthalene from fluids produced from a relatively permeable formation, comprising: separating naphthalene from the produced fluids, wherein the produced fluids are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing fluids from the formation wherein the produced fluids comprise naphthalene.
 6067. The method of claim 6066, further comprising controlling a fluid pressure within at least a portion of the formation.
 6068. The method of claim 6066, further comprising controlling a temperature gradient within at least a portion of the formation.
 6069. The method of claim 6066, further comprising controlling a temperature within at least a portion of the formation.
 6070. The method of claim 6066, further comprising controlling a heating rate within at least a portion of the formation.
 6071. The method of claim 6066 wherein separating at least some naphthalene from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.
 6072. The method of claim 6066 wherein separating at least some naphthalene from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.
 6073. The method of claim 6066 wherein separating at least some naphthalene from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the naphthalene from the heart cut.
 6074. The method of claim 6066 wherein separating at least some naphthalene from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the naphthalene from the naphtha fraction.
 6075. The method of claim 6066, wherein separating at least some naphthalene from the produced fluids further comprises removing an naphthalene fraction from the produced fluids, and separating at least a portion of the naphthalene from the naphthalene fraction.
 6076. The method of claim 6066 wherein separating the naphthalene from the produced fluids further comprises removing naphthalene using distillation.
 6077. The method of claim 6066 wherein separating the naphthalene from the produced fluids further comprises removing naphthalene using crystallization.
 6078. The method of claim 6066, further comprising removing at least a portion of the naphthalene prior to hydrotreating produced fluids.
 6079. The method of claim 6066, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6080. The method of claim 6066, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6081. The method of claim 6066, wherein at least one heat source comprises a heater.
 6082. A method of enhancing anthracene production from a relatively permeable formation, comprising: controlling at least one condition within at least a portion of the formation to enhance production of anthracene in formation fluid, wherein the formation fluid is obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing formation fluids from the formation.
 6083. The method of claim 6082, further comprising separating at least a portion of the anthracene from the produced fluids.
 6084. The method of claim 6082 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.
 6085. The method of claim 6082 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.
 6086. The method of claim 6082 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.
 6087. The method of claim 6082 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.
 6088. The method of claim 6082, further comprising separating the produced fluids into one or more fractions using distillation.
 6089. The method of claim 6082, further comprising separating the produced fluids into one or more fractions using condensation.
 6090. The method of claim 6082, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some anthracene from the heart cut.
 6091. The method of claim 6082, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a anthracene fraction, and further comprising providing the anthracene fraction to an extraction unit, and separating at least some anthracene from the anthracene fraction.
 6092. The method of claim 6082, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6093. The method of claim 6082, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6094. The method of claim 6082, wherein at least one heat source comprises a heater.
 6095. A method of separating anthracene from fluids produced from a relatively permeable formation, comprising: separating anthracene from the produced fluids, wherein the produced fluids are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing fluids from the formation wherein the produced fluids comprise anthracene.
 6096. The method of claim 6095, further comprising controlling a fluid pressure within at least a portion of the formation.
 6097. The method of claim 6095, further comprising controlling a temperature gradient within at least a portion of the formation.
 6098. The method of claim 6095, further comprising controlling a temperature within at least a portion of the formation.
 6099. The method of claim 6095, further comprising controlling a heating rate within at least a portion of the formation.
 6100. The method of claim 6095, wherein separating at least some anthracene from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.
 6101. The method of claim 6095, wherein separating at least some anthracene from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.
 6102. The method of claim 6095, wherein separating at least some anthracene from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the anthracene from the heart cut.
 6103. The method of claim 6095, wherein separating at least some anthracene from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the anthracene from the naphtha fraction.
 6104. The method of claim 6095, wherein separating at least some anthracene from the produced fluids fiber comprises removing an anthracene fraction from the produced fluids, and separating at least a portion of the anthracene from the anthracene fraction.
 6105. The method of claim 6095, wherein separating the anthracene from the produced fluids further comprises removing anthracene using distillation.
 6106. The method of claim 6095, wherein separating the anthracene from the produced fluids further comprises removing anthracene using crystallization.
 6107. The method of claim 6095, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6108. The method of claim 6095, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6109. The method of claim 6095, wherein at least one heat source comprises a heater.
 6110. A method of separating ammonia from fluids produced from a relatively permeable formation, comprising: separating at least a portion of the ammonia from the produced fluid, wherein the produced fluids are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing fluids from the formation.
 6111. The method of claim 6110 wherein the produced fluids are pyrolyzation fluids.
 6112. The method of claim 6110 wherein separating at least a portion of the ammonia from the produced fluids further comprises providing at least a portion of the produced fluids to a sour water stripper.
 6113. The method of claim 6110 wherein separating at least a portion of the ammonia from the produced fluids further comprises separating the produced fluids into one or more fractions, and providing at least a portion of the one or more fractions to a stripping unit.
 6114. The method of claim 6110, further comprising using at least a portion of the separated ammonia to generate ammonium sulfate.
 6115. The method of claim 6110, further comprising using at least a portion of the separated ammonia to generate urea.
 6116. The method of claim 6110 wherein the produced fluids comprise carbon dioxide, and further comprising separating the carbon dioxide from the produced fluids, and reacting the carbon dioxide with at least some ammonia to form urea.
 6117. The method of claim 6110 wherein the produced fluids comprise hydrogen sulfide, and further comprising separating the hydrogen sulfide from the produced fluids, converting at least some hydrogen sulfide into sulfuric acid, and reacting at lest some sulfuric acid with at lease some ammonia to form ammonium sulfate.
 6118. The method of claim 6110 wherein the produced fluids further comprise hydrogen sulfide, and further comprising separating at least a portion of the hydrogen sulfide from the produced fluids, and converting at least some hydrogen sulfide into sulfuric acid.
 6119. The method of claim 6110, further comprising generating ammonium bicarbonate using separated ammonia.
 6120. The method of claim 6110, further comprising providing separated ammonia to a fluid comprising carbon dioxide to generate ammonium bicarbonate.
 6121. The method of claim 6110, further comprising providing separated ammonia to at least some synthesis gas to generate ammonium bicarbonate.
 6122. The method of claim 6110, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6123. The method of claim 6110, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6124. The method of claim 6110, wherein at least one heat source comprises a heater.
 6125. A method of generating ammonia from fluids produced from a relatively permeable formation, comprising: hydrotreating at least a portion of the produced fluids to generate ammonia wherein the produced fluids are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing fluids from the formation.
 6126. The method of claim 6125 wherein the produced fluids are pyrolyzation fluids.
 6127. The method of claim 6125, further comprising separating at least a portion of the ammonia from the hydrotreated fluids.
 6128. The method of claim 6125, further comprising using at least a portion of the ammonia to generate ammonium sulfate.
 6129. The method of claim 6125, further comprising using at least a portion of the ammonia to generate urea.
 6130. The method of claim 6125 wherein the produced fluids further comprise carbon dioxide, and further comprising separating at least a portion of the carbon dioxide from the produced fluids, and reacting at least the portion of the carbon dioxide with at least a portion of ammonia to form urea.
 6131. The method of claim 6125 wherein the produced fluids further comprise hydrogen sulfide, and further comprising separating at least a portion of the hydrogen sulfide from the produced fluids, converting at least some hydrogen sulfide into sulfuric acid, and reacting at least some sulfuric acid with at least a portion of the ammonia to form ammonium sulfate.
 6132. The method of claim 6125 wherein the produced fluids further comprise hydrogen sulfide, and further comprising separating at least a portion of the hydrogen sulfide from the produced fluids, and converting at least some hydrogen sulfide into sulfuric acid.
 6133. The method of claim 6125, further comprising generating ammonium bicarbonate using at least a portion of the ammonia.
 6134. The method of claim 6125, further comprising providing at least a portion of the ammonia to a fluid comprising carbon dioxide to generate ammonium bicarbonate.
 6135. The method of claim 6125, further comprising providing at least a portion of the ammonia to at least some synthesis gas to generate ammonium bicarbonate.
 6136. The method of claim 6125, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6137. The method of claim 6125, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6138. The method of claim 6125, wherein at least one heat source comprises a heater.
 6139. A method of enhancing pyridines production from a relatively permeable formation, comprising: controlling at least one condition within at least a portion of the formation to enhance production of pyridines in formation fluid, wherein the formation fluid is obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing formation fluids from the formation.
 6140. The method of claim 6139, further comprising separating at least a portion of the pyridines from the produced fluids.
 6141. The method of claim 6139 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.
 6142. The method of claim 6139 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.
 6143. The method of claim 6139 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.
 6144. The method of claim 6139 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.
 6145. The method of claim 6139, further comprising separating the produced fluids into one or more fractions using distillation.
 6146. The method of claim 6139, further comprising separating the produced fluids into one or more fractions using condensation.
 6147. The method of claim 6139, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some pyridines from the heart cut.
 6148. The method of claim 6139, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a pyridines fraction, and further comprising providing the pyridines fraction to an extraction unit, and separating at least some pyridines from the pyridines fraction.
 6149. The method of claim 6139, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6150. The method of claim 6139, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6151. The method of claim 6139, wherein at least one heat source comprises a heater.
 6152. A method of separating pyridines from fluids produced from a relatively permeable formation, comprising: separating pyridines from the produced fluids, wherein the produced fluids are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing fluids from the formation wherein the produced fluids comprise pyridines.
 6153. The method of claim 6152, further comprising controlling a fluid pressure within at least a portion of the formation.
 6154. The method of claim 6152, further comprising controlling a temperature gradient within at least a portion of the formation.
 6155. The method of claim 6152, further comprising controlling a temperature within at least a portion of the formation.
 6156. The method of claim 6152, further comprising controlling a heating rate within at least a portion of the formation.
 6157. The method of claim 6152 wherein separating at least some pyridines from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.
 6158. The method of claim 6152 wherein separating at least some pyridines from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.
 6159. The method of claim 6152 wherein separating at least some pyridines from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the pyridines from the heart cut.
 6160. The method of claim 6152 wherein separating at least some pyridines from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the pyridines from the naphtha fraction.
 6161. The method of claim 6152, wherein separating at least some pyridines from the produced fluids further comprises removing an pyridines fraction from the produced fluids, and separating at least a portion of the pyridines from the pyridines fraction.
 6162. The method of claim 6152, wherein separating the pyridines from the produced fluids further comprises removing pyridines using distillation.
 6163. The method of claim 6152, wherein separating the pyridines from the produced fluids further comprises removing pyridines using crystallization.
 6164. The method of claim 6152, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6165. The method of claim 6152, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6166. The method of claim 6152, wherein at least one heat source comprises a heater.
 6167. A method of enhancing pyrroles production from a relatively permeable formation, comprising: controlling at least one condition within at least a portion of the formation to enhance production of pyrroles in formation fluid, wherein the formation fluid is obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing formation fluids from the formation.
 6168. The method of claim 6167, further comprising separating at least a portion of the pyrroles from the produced fluids.
 6169. The method of claim 6167 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.
 6170. The method of claim 6167 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.
 6171. The method of claim 6167 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.
 6172. The method of claim 6167 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.
 6173. The method of claim 6167, further comprising separating the produced fluids into one or more fractions using distillation.
 6174. The method of claim 6167, further comprising separating the produced fluids into one or more fractions using condensation.
 6175. The method of claim 6167, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some pyrroles from the heart cut.
 6176. The method of claim 6167, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a pyrroles fraction, and further comprising providing the pyrroles fraction to an extraction unit, and separating at least some pyrroles from the pyrroles fraction.
 6177. The method of claim 6167, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6178. The method of claim 6167, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6179. The method of claim 6167, wherein at least one heat source comprises a heater.
 6180. A method of separating pyrroles from fluids produced from a relatively permeable formation, comprising: separating pyrroles from the produced fluids, wherein the produced fluids are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing fluids from the formation wherein the produced fluids comprise pyrroles.
 6181. The method of claim 6180, further comprising controlling a fluid pressure within at least a portion of the formation.
 6182. The method of claim 6180, further comprising controlling a temperature gradient within at least a portion of the formation.
 6183. The method of claim 6180, further comprising controlling a temperature within at least a portion of the formation.
 6184. The method of claim 6180, further comprising controlling a heating rate within at least a portion of the formation.
 6185. The method of claim 6180 wherein separating at least some pyrroles from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.
 6186. The method of claim 6180 wherein separating at least some pyrroles from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.
 6187. The method of claim 6180 wherein separating at least some pyrroles from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the pyrroles from the heart cut.
 6188. The method of claim 6180 wherein separating at least some pyrroles from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the pyrroles from the naphtha fraction.
 6189. The method of claim 6180, wherein separating at least some pyrroles from the produced fluids further comprises removing an pyrroles fraction from the produced fluids, and separating at least a portion of the pyrroles from the pyrroles fraction.
 6190. The method of claim 6180, wherein separating the pyrroles from the produced fluids further comprises removing pyrroles using distillation.
 6191. The method of claim 6180, wherein separating the pyrroles from the produced fluids further comprises removing pyrroles using crystallization.
 6192. The method of claim 6180, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6193. The method of claim 6180, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6194. The method of claim 6180, wherein at least one heat source comprises a heater.
 6195. A method of enhancing thiophenes production from a relatively permeable formation, comprising: controlling at least one condition within at least a portion of the formation to enhance production of thiophenes in formation fluid, wherein the formation fluid is obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing formation fluids from the formation.
 6196. The method of claim 6195, further comprising separating at least a portion of the thiophenes from the produced fluids.
 6197. The method of claim 6195 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.
 6198. The method of claim 6195 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.
 6199. The method of claim 6195 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.
 6200. The method of claim 6195 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.
 6201. The method of claim 6195, further comprising separating the produced fluids into one or more fractions using distillation.
 6202. The method of claim 6195, further comprising separating the produced fluids into one or more fractions using condensation.
 6203. The method of claim 6195, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some thiophenes from the heart cut.
 6204. The method of claim 6195, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a thiophenes fraction, and further comprising providing the thiophenes fraction to an extraction unit, and separating at least some thiophenes from the thiophenes fraction.
 6205. The method of claim 6195, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6206. The method of claim 6195, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6207. The method of claim 6195, wherein at least one heat source comprises a heater.
 6208. A method of separating thiophenes from fluids produced from a relatively permeable formation, comprising: separating thiophenes from the produced fluids, wherein the produced fluids are obtained by: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and producing fluids from the formation wherein the produced fluids comprise thiophenes.
 6209. The method of claim 6208, further comprising controlling a fluid pressure within at least a portion of the formation.
 6210. The method of claim 6208, further comprising controlling a temperature gradient within at least a portion of the formation.
 6211. The method of claim 6208, further comprising controlling a temperature within at least a portion of the formation.
 6212. The method of claim 6208, further comprising controlling a heating rate within at least a portion of the formation.
 6213. The method of claim 6208 wherein separating at least some thiophenes from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.
 6214. The method of claim 6208 wherein separating at least some thiophenes from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.
 6215. The method of claim 6208 wherein separating at least some thiophenes from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the thiophenes from the heart cut.
 6216. The method of claim 6208 wherein separating at least some thiophenes from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the thiophenes from the naphtha fraction.
 6217. The method of claim 6208 wherein separating at least some thiophenes from the produced fluids further comprises removing an thiophenes fraction from the produced fluids, and separating at least a portion of the thiophenes from the thiophenes fraction.
 6218. The method of claim 6208 wherein separating the thiophenes from the produced fluids further comprises removing thiophenes using distillation.
 6219. The method of claim 6208 wherein separating the thiophenes from the produced fluids further comprises removing thiophenes using crystallization.
 6220. The method of claim 6208, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.
 6221. The method of claim 6208, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6222. The method of claim 6208, wherein at least one heat source comprises a heater.
 6223. A method of treating a relatively permeable formation comprising: providing a barrier to at least a portion of the formation to inhibit migration of fluids into or out of a treatment area of the formation; providing heat from one or more heat sources to the treatment area; allowing the heat to transfer from the treatment area to a selected section of the formation; and producing fluids from the formation.
 6224. The method of claim 6223, wherein the heat provided from at least one of the one or more heat sources is transferred to at least a portion of the formation substantially by conduction.
 6225. The method of claim 6223, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6226. The method of claim 6223, wherein at least one of the one or more of the heat sources comprises a heater.
 6227. The method of claim 6223, further comprising hydraulically isolating the treatment area from a surrounding portion of the formation.
 6228. The method of claim 6223, further comprising pyrolyzing at least a portion of hydrocarbon containing material within the treatment area.
 6229. The method of claim 6223, further comprising generating synthesis gas in at least a portion of the treatment area.
 6230. The method of claim 6223, further comprising controlling a pressure within the treatment area.
 6231. The method of claim 6223, further comprising controlling a temperature within the treatment area.
 6232. The method of claim 6223, further comprising controlling a heating rate within the treatment area.
 6233. The method of claim 6223, further comprising controlling an amount of fluid removed from the treatment area.
 6234. The method of claim 6223, wherein at least section of the barrier comprises one or more sulfur wells.
 6235. The method of claim 6223, wherein at least section of the barrier comprises one or more dewatering wells.
 6236. The method of claim 6223, wherein at least section of the barrier comprises one or more injection wells and one or more dewatering wells.
 6237. The method of claim 6223, wherein providing a barrier comprises: providing a circulating fluid to the a portion of the formation surrounding the treatment area; and removing the circulating fluid proximate the treatment area.
 6238. The method of claim 6223, wherein at least section of the barrier comprises a ground cover on a surface of the earth.
 6239. The method of claim 6238, wherein at least section of the ground cover is sealed to a surface of the earth.
 6240. The method of claim 6223, further comprising inhibiting a release of formation fluid to the earth's atmosphere with a ground cover; and freezing at least a portion of the ground cover to a surface of the earth.
 6241. The method of claim 6223, further comprising inhibiting a release of formation fluid to the earth's atmosphere.
 6242. The method of claim 6223, further comprising inhibiting fluid seepage from a surface of the earth into the treatment area.
 6243. The method of claim 6223, wherein at least a section of the barrier is naturally occurring.
 6244. The method of claim 6223, wherein at least a section of the barrier comprises a low temperature zone.
 6245. The method of claim 6223, wherein at least a section of the barrier comprises a frozen zone.
 6246. The method of claim 6223, wherein the barrier comprises an installed portion and a naturally occurring portion.
 6247. The method of claim 6223, further comprising: hydraulically isolating the treatment area from a surrounding portion of the formation; and maintaining a fluid pressure within the treatment area at a pressure greater than about a fluid pressure within the surrounding portion of the formation.
 6248. The method of claim 6223, wherein at least a section of the barrier comprises an impermeable section of the formation.
 6249. The method of claim 6223, wherein the barrier comprises a self-sealing portion.
 6250. The method of claim 6223, wherein the one or more heat sources are positioned at a distance greater than about 5 m from the barrier.
 6251. The method of claim 6223, wherein at least one of the one or more heat sources is positioned at a distance less than about 1.5 m from the barrier.
 6252. The method of claim 6223, wherein at least a portion of the barrier comprises a low temperature zone, and further comprising lowering a temperature within the low temperature zone to a temperature less than about a freezing temperature of water.
 6253. The method of claim 6223, wherein the barrier comprises a barrier well and further comprising positioning at least a portion of the barrier well below a water table of the formation.
 6254. The method of claim 6223, wherein the treatment area comprises a first treatment area and a second treatment area, and further comprising: treating the first treatment area using a first treatment process; and treating the second treatment area using a second treatment process.
 6255. A method of treating a relatively permeable formation in situ, comprising: providing a refrigerant to a plurality of barrier wells placed in a portion of the formation; establishing a frozen barrier zone to inhibit migration of fluids into or out of a treatment area; providing heat from one or more heat sources to the treatment area; allowing the heat to transfer from the treatment area to a selected section; and producing fluids from the formation.
 6256. The method of claim 6255, wherein the heat provided from at least one of the one or more heat sources is transferred to at least a portion of the formation substantially by conduction.
 6257. The method of claim 6255, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6258. The method of claim 6255, wherein at least one of the one or more of the heat sources comprises a heater.
 6259. The method of claim 6255, further comprising controlling a fluid pressure within the treatment area.
 6260. The method of claim 6255, wherein the frozen barrier zone is proximate the treatment area of the formation.
 6261. The method of claim 6255, further comprising hydraulically isolating the treatment area from a surrounding portion of the formation.
 6262. The method of claim 6255, further comprising thermally isolating the treatment area from a surrounding portion of the formation.
 6263. The method of claim 6255, further comprising maintaining the fluid pressure above a hydrostatic pressure of the formation.
 6264. The method of claim 6255, further comprising removing liquid water from at least a portion of the treatment area.
 6265. The method of claim 6255, wherein the treatment area is below a water table of the formation.
 6266. The method of claim 6255, wherein at least one barrier well of the plurality of barrier wells comprises a corrosion inhibitor.
 6267. The method of claim 6255, wherein heating is initiated after formation of the frozen barrier zone.
 6268. The method of claim 6255, wherein the refrigerant comprises one or more hydrocarbons.
 6269. The method of claim 6255, wherein the refrigerant comprises propane.
 6270. The method of claim 6255, wherein the refrigerant comprises isobutane.
 6271. The method of claim 6255, wherein the refrigerant comprises cyclopentane.
 6272. The method of claim 6255, wherein the refrigerant comprises ammonia.
 6273. The method of claim 6255, wherein the refrigerant comprises an aqueous salt mixture.
 6274. The method of claim 6255, wherein the refrigerant comprises an organic acid salt.
 6275. The method of claim 6255, wherein the refrigerant comprises a salt of an organic acid.
 6276. The method of claim 6255, wherein the refrigerant comprises an organic acid.
 6277. The method of claim 6255, wherein the refrigerant has a freezing point of less than about minus 60 degrees Celsius.
 6278. The method of claim 6255, wherein the refrigerant comprises calcium chloride.
 6279. The method of claim 6255, wherein the refrigerant comprises lithium chloride.
 6280. The method of claim 6255, wherein the refrigerant comprises liquid nitrogen.
 6281. The method of claim 6255, wherein the refrigerant is provided at a temperature of less than about minus 50 degrees Celsius.
 6282. The method of claim 6255, wherein the refrigerant comprises carbon dioxide.
 6283. The method of claim 6255, wherein at least one of the plurality of barrier wells is located along strike of a hydrocarbon containing portion of the formation.
 6284. The method of claim 6255, wherein at least one of the plurality of barrier wells is located along dip of a hydrocarbon containing portion of the formation.
 6285. The method of claim 6255, wherein the one or more heat sources are placed greater than about 5 m from a frozen barrier zone.
 6286. The method of claim 6255, wherein at least one of the one or more heat sources is positioned less than about 1.5 m from a frozen barrier zone.
 6287. The method of claim 6255, wherein a distance between a center of at least one barrier well and a center of at least one adjacent barrier well is greater than about 2 m.
 6288. The method of claim 6255, further comprising desorbing methane from the formation.
 6289. The method of claim 6255, further comprising pyrolyzing at least some hydrocarbon containing material within the treatment area.
 6290. The method of claim 6255, further comprising producing synthesis gas from at least a portion of the formation.
 6291. The method of claim 6255, further comprising: providing a solvent to the treatment area such that the solvent dissolves a component in the treatment area; and removing the solvent from the treatment area, wherein the removed solvent comprises the component.
 6292. The method of claim 6255, further comprising sequestering a compound in at least a portion of the treatment area.
 6293. The method of claim 6255, further comprising thawing at least a portion of the frozen barrier zone; and wherein material in a thawed barrier zone area is substantially unaltered by the application of heat.
 6294. The method of claim 6255, wherein a location of the frozen barrier zone has been selected using a flow rate of groundwater and wherein the selected groundwater flow rate is less than about 50 m/day.
 6295. The method of claim 6255, further comprising providing water to the frozen barrier zone.
 6296. The method of claim 6255, further comprising positioning one or more monitoring wells outside the frozen barrier zone, and then providing a tracer to the treatment area, and then monitoring for movement of the tracer at the monitoring wells.
 6297. The method of claim 6255, further comprising: positioning one or more monitoring wells outside the frozen barrier zone; then providing an acoustic pulse to the treatment area; and then monitoring for the acoustic pulse at the monitoring wells.
 6298. The method of claim 6255, wherein a fluid pressure within the treatment area can be controlled at fluid pressures different from a fluid pressure that exists in a surrounding portion of the formation.
 6299. The method of claim 6255, wherein fluid pressure within an area at least partially bounded by the frozen barrier zone can be controlled higher than, or lower than, hydrostatic pressures that exist in a surrounding portion of the formation.
 6300. The method of claim 6255, further comprising controlling compositions of fluids produced from the formation by controlling the fluid pressure within an area at least partially bounded by the frozen barrier zone.
 6301. The method of claim 6255, wherein a portion of at least one of the plurality of barrier wells is positioned below a water table of the formation.
 6302. A method of treating a relatively permeable formation comprising: providing a refrigerant to one or more barrier wells placed in a portion of the formation; establishing a low temperature zone proximate a treatment area of the formation; providing heat from one or more heat sources to a treatment area of the formation; allowing the heat to transfer from the treatment area to a selected section of the formation; and producing fluids from the formation.
 6303. The method of claim 6302, further comprising forming a frozen barrier zone within the low temperature zone, wherein the frozen barrier zone hydraulically isolates the treatment area from a surrounding portion of the formation.
 6304. The method of claim 6302, further comprising forming a frozen barrier zone within the low temperature zone, and wherein fluid pressure within an area at least partially bounded by the frozen barrier zone can be controlled at different fluid pressures from the fluid pressures that exist outside of the frozen barrier zone.
 6305. The method of claim 6302, further comprising forming a frozen barrier zone within the low temperature zone, and wherein fluid pressure within an area at least partially bounded by the frozen barrier zone can be controlled higher than, or lower than, hydrostatic pressures that exist outside of the frozen barrier zone.
 6306. The method of claim 6302, further comprising forming a frozen barrier zone within the low temperature zone, and wherein fluid pressure within an area at least partially bounded by the frozen barrier zone can be controlled higher than, or lower than, hydrostatic pressures that exist outside of the frozen barrier zone, and further comprising controlling compositions of fluids produced from the formation by controlling the fluid pressure within the area at least partially bounded by the frozen barrier zone.
 6307. The method of claim 6302, further comprising thawing at least a portion of the low temperature zone, wherein material within the thawed portion is substantially unaltered by the application of heat such that the structural integrity of the relatively permeable formation is substantially maintained.
 6308. The method of claim 6302, wherein an inner boundary of the low temperature zone is determined by monitoring a pressure wave using one or more piezometers.
 6309. The method of claim 6302, further comprising controlling a fluid pressure within the treatment area at a pressure less than about a formation fracture pressure.
 6310. The method of claim 6302, further comprising positioning one or more monitoring wells outside the frozen barrier zone, and then providing an acoustic pulse to the treatment area, and then monitoring for the acoustic pulse at the monitoring wells.
 6311. The method of claim 6302, further comprising positioning a segment of at least one of the one or more barrier wells below a water table of the formation.
 6312. The method of claim 6302, further comprising positioning the one or more barrier wells to establish a continuous low temperature zone.
 6313. The method of claim 6302, wherein the refrigerant comprises one or more hydrocarbons.
 6314. The method of claim 6302, wherein the refrigerant comprises propane.
 6315. The method of claim 6302, wherein the refrigerant comprises isobutane.
 6316. The method of claim 6302, wherein the refrigerant comprises cyclopentane.
 6317. The method of claim 6302, wherein the refrigerant comprises ammonia.
 6318. The method of claim 6302, wherein the refrigerant comprises an aqueous salt mixture.
 6319. The method of claim 6302, wherein the refrigerant comprises an organic acid salt.
 6320. The method of claim 6302, wherein the refrigerant comprises a salt of an organic acid.
 6321. The method of claim 6302, wherein the refrigerant comprises an organic acid.
 6322. The method of claim 6302, wherein the refrigerant has a freezing point of less than about minus 60 degrees Celsius.
 6323. The method of claim 6302, wherein the refrigerant is provided at a temperature of less than about minus 50 degrees Celsius.
 6324. The method of claim 6302, wherein the refrigerant is provided at a temperature of less than about minus 25 degrees Celsius.
 6325. The method of claim 6302, wherein the refrigerant comprises carbon dioxide.
 6326. The method of claim 6302, further comprising: cooling at least a portion of the refrigerant in an absorption refrigeration unit; and providing a thermal energy source to the absorption refrigeration unit.
 6327. The method of claim 6302, wherein the thermal energy source comprises water.
 6328. The method of claim 6302, wherein the thermal energy source comprises steam.
 6329. The method of claim 6302, wherein the thermal energy source comprises at least a portion of the produced fluids.
 6330. The method of claim 6302, wherein the thermal energy source comprises exhaust gas.
 6331. A method of treating a relatively permeable formation, comprising: inhibiting migration of fluids into or out of a treatment area of the formation from a surrounding portion of the formation; providing heat from one or more heat sources to at least a portion of the treatment area; allowing the heat to transfer from at least the portion to a selected section of the formation; and producing fluids from the formation.
 6332. The method of claim 6331, wherein the heat provided from at least one of the one or more heat sources is transferred to at least a portion of the formation substantially by conduction.
 6333. The method of claim 6331, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6334. The method of claim 6331, wherein at least one of the one or more of the heat sources comprises a heater.
 6335. The method of claim 6331, further comprising providing a barrier to at least a portion of the formation.
 6336. The method of claim 6335, wherein at least section of the barrier comprises one or more sulfur wells.
 6337. The method of claim 6335, wherein at least section of the barrier comprises one or more pumping wells.
 6338. The method of claim 6335, wherein at least section of the barrier comprises one or more injection wells and one or more pumping wells.
 6339. The method of claim 6335, wherein at least a section of the barrier is naturally occurring.
 6340. The method of claim 6331, further comprises establishing a barrier in at least a portion of the formation, and wherein heat is provided after at least a portion of the barrier has been established.
 6341. The method of claim 6331, further comprising establishing a barrier in at least a portion of the formation, and wherein heat is provided while at least a portion of the barrier is being established.
 6342. The method of claim 6331, further comprising providing a barrier to at least a portion of the formation, and wherein heat is provided before the barrier is established.
 6343. The method of claim 6331, further comprising controlling an amount of fluid removed from the treatment area.
 6344. The method of claim 6331, wherein isolating a treatment area from a surrounding portion of the formation comprises providing a low temperature zone to at least a portion of the formation.
 6345. The method of claim 6331, wherein isolating a treatment area from a surrounding portion of the formation comprises providing a frozen barrier zone to at least a portion of the formation.
 6346. The method of claim 6331, wherein isolating a treatment area from a surrounding portion of the formation comprises providing a grout wall.
 6347. The method of claim 6331, further comprising inhibiting flow of a water into or out of at least a portion of a treatment area.
 6348. The method of claim 6331, further comprising: providing a material to the treatment area; and storing at least some of the material within the treatment area.
 6349. A method of treating a relatively permeable formation, comprising: providing a barrier to a portion of the formation, wherein the portion has previously undergone an in situ conversion process; and inhibiting migration of fluids into and out of the converted portion to a surrounding portion of the formation.
 6350. The method of claim 6349, wherein the barrier comprises a frozen barrier zone.
 6351. The method of claim 6349, wherein the barrier comprises a low temperature zone.
 6352. The method of claim 6349, wherein the barrier comprises a sealing mineral phase.
 6353. The method of claim 6349, wherein the barrier comprises a sulfur barrier.
 6354. The method of claim 6349, wherein the contaminant comprises a metal.
 6355. The method of claim 6349, wherein the contaminant comprises organic residue.
 6356. A method of treating a relatively permeable formation, comprising: introducing a first fluid into at least a portion of the formation, wherein the portion has previously undergone an in situ conversion process; producing a mixture of the first fluid and a second fluid from the formation; and providing at least a portion of the mixture to an energy producing unit.
 6357. The method of claim 6356, wherein the first fluid is selected to recover heat from the formation.
 6358. The method of claim 6356, wherein the first fluid is selected to recover heavy compounds from the formation.
 6359. The method of claim 6356, wherein the first fluid is selected to recover hydrocarbons from the formation.
 6360. The method of claim 6356, wherein the mixture comprises an oxidizable heat recovery fluid.
 6361. The method of claim 6356, wherein producing the mixture remediates the portion of the formation by removing contaminants from the formation in the mixture.
 6362. The method of claim 6356, wherein the first fluid comprises a hydrocarbon fluid.
 6363. The method of claim 6356, wherein the first fluid comprises methane.
 6364. The method of claim 6356, wherein the first fluid comprises ethane.
 6365. The method of claim 6356, wherein the first fluid comprises molecular hydrogen.
 6366. The method of claim 6356, wherein the energy producing unit comprises a turbine, and generating electricity by passing mixture through the energy producing unit.
 6367. The method of claim 6356, further comprising combusting mixture within the energy producing unit.
 6368. The method of claim 6356, further comprising inhibiting spread of the mixture from the portion of the formation with a barrier.
 6369. A method of treating a relatively permeable formation, comprising: providing a first fluid to at least a portion of a treatment area, wherein the treatment area includes one or more components; producing a fluid from the formation wherein the produced fluid comprises first fluid and at least some of the one or more components; and wherein the treatment area is obtained by providing heat from heat sources to a portion of a relatively permeable formation to convert a portion of hydrocarbons to desired products and removing a portion of the desired hydrocarbons from the formation.
 6370. The method of claim 6369, wherein the first fluid comprises water.
 6371. The method of claim 6369, wherein the first fluid comprises carbon dioxide.
 6372. The method of claim 6369, wherein the first fluid comprises steam.
 6373. The method of claim 6369, wherein the first fluid comprises air.
 6374. The method of claim 6369, wherein the first fluid comprises a combustible gas.
 6375. The method of claim 6369, wherein the first fluid comprises hydrocarbons.
 6376. The method of claim 6369, wherein the first fluid comprises methane.
 6377. The method of claim 6369, wherein the first fluid comprises ethane.
 6378. The method of claim 6369, wherein the first fluid comprises molecular hydrogen.
 6379. The method of claim 6369, wherein the first fluid comprises propane.
 6380. The method of claim 6369, further comprising reacting a portion of the contaminants with the first fluid.
 6381. The method of claim 6369, further comprising providing at least a portion of the produced fluid to an energy generating unit to generate electricity.
 6382. The method of claim 6369, further comprising providing at least a portion of the produced fluid to a combustor.
 6383. The method of claim 6369, wherein a frozen barrier defines at least a segment of a barrier within the formation, allowing a portion of the frozen barrier to thaw prior to providing the first fluid to the treatment area, and providing at least some of the first fluid into the thawed portion of the barrier.
 6384. The method of claim 6369, wherein a volume of first fluid provided to the treatment area is greater than about one pore volume of the treatment area.
 6385. The method of claim 6369, further comprising separating contaminants from the first fluid.
 6386. A method of recovering thermal energy from a heated relatively permeable formation, comprising: injecting a heat recovery fluid into a heated portion of the formation; allowing heat from the portion of the formation to transfer to the heat recovery fluid; and producing fluids from the formation.
 6387. The method of claim 6386, wherein the heat recovery fluid comprises water.
 6388. The method of claim 6386, wherein the heat recovery fluid comprises saline water.
 6389. The method of claim 6386, wherein the heat recovery fluid comprises non-potable water.
 6390. The method of claim 6386, wherein the heat recovery fluid comprises alkaline water.
 6391. The method of claim 6386, wherein the heat recovery fluid comprises hydrocarbons.
 6392. The method of claim 6386, wherein the heat recovery fluid comprises an inert gas.
 6393. The method of claim 6386, wherein the heat recovery fluid comprises carbon dioxide.
 6394. The method of claim 6386, wherein the heat recovery fluid comprises a product stream produced by an in situ conversion process.
 6395. The method of claim 6386, further comprising vaporizing at least some of the heat recovery fluid.
 6396. The method of claim 6386, wherein an average temperature of the portion of the post treatment formation prior to injection of heat recovery fluid is greater than about 300° C.
 6397. The method of claim 6386, further comprising providing the heat recovery fluid to the formation through a heater well.
 6398. The method of claim 6386, wherein fluids are produced from one or more production wells in the formation.
 6399. The method of claim 6386, further comprising providing at least some of the produced fluids to a treatment process in a section of the formation.
 6400. The method of claim 6386, further comprising recovering at least some of the heat from the produced fluids.
 6401. The method of claim 6386, further comprising providing at least some of the produced fluids to a power generating unit.
 6402. The method of claim 6386, further comprising providing at least some of the produced fluids to a heat exchange mechanism.
 6403. The method of claim 6386, further comprising providing at least some of the produced fluids to a steam cracking unit.
 6404. The method of claim 6386, further comprising providing at least some of the produced fluids to a hydrotreating unit.
 6405. The method of claim 6386, further comprising providing at least some of the produced fluids to a distillation column.
 6406. The method of claim 6386, wherein the heat recovery fluid comprises carbon dioxide, and wherein at least some of the carbon dioxide is adsorbed onto the surface of carbon in the formation.
 6407. The method of claim 6386, wherein the heat recovery fluid comprises carbon dioxide, and further comprising: allowing at least some hydrocarbons within the formation to desorb from the formation; and producing at least some of the desorbed hydrocarbons from the formation.
 6408. The method of claim 6386, further comprising providing at least some of the produced fluids to a treatment process in a section of the formation.
 6409. The method of claim 6386, wherein the heat recovery fluid is saline water, and further comprising: providing carbon dioxide to the portion of the formation; and precipitating carbonate compounds.
 6410. The method of claim 6386, further comprising reducing an average temperature of the formation to a temperature less than about an ambient boiling temperature of water at a post treatment pressure.
 6411. The method of claim 6386, wherein the produced fluids comprise low molecular weight hydrocarbons.
 6412. The method of claim 6386, wherein the produced fluids comprise hydrocarbons.
 6413. The method of claim 6386, wherein the produced fluids comprise heat recovery fluid.
 6414. A method of treating a relatively permeable formation, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; controlling at least one condition within the selected section; producing a mixture from the formation; and wherein at least the one condition is controlled such that the mixture comprises a carbon dioxide emission level less than about a selected carbon dioxide emission level.
 6415. The method of claim 6414, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6416. The method of claim 6414, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6417. The method of claim 6414, wherein at least one of the one or more of the heat sources comprises a heater.
 6418. The method of claim 6414, wherein the selected carbon dioxide emission level is less than about 5.6×10⁻⁸ kg CO₂ produced for every Joule of energy.
 6419. The method of claim 6414, wherein the selected carbon dioxide emission level is less than about 1.6×10⁻⁸ kg CO₂ produced for every Joule of energy.
 6420. The method of claim 6414, wherein the selected carbon dioxide emission level is less than about 1.6×10⁻¹⁰ kg CO₂ produced for every Joule of energy.
 6421. The method of claim 6414, further comprising blending the mixture with a fluid to form a blended product comprising a carbon dioxide emission level less than about the selected baseline carbon dioxide emission level.
 6422. The method of claim 6414, wherein controlling conditions within a selected section comprises controlling a pressure within the selected section.
 6423. The method of claim 6414, wherein controlling conditions within a selected section comprises controlling an average temperature within the selected section.
 6424. The method of claim 6414, wherein controlling conditions within a selected section comprises controlling an average heating rate within the selected section.
 6425. A method for producing molecular hydrogen from a relatively permeable formation, comprising: providing heat from one or more heat sources to at least one portion of the formation such that carbon dioxide production is minimized; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; producing a mixture comprising molecular hydrogen from the formation; and controlling the heat from the one or more heat sources to enhance production of molecular hydrogen.
 6426. The method of claim 6425, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6427. The method of claim 6425, wherein at least one of the one or more of the heat sources comprises a heater.
 6428. The method of claim 6425, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6429. The method of claim 6425, wherein controlling the heat comprises controlling a temperature proximate the production wellbore at or above a decomposition temperature of methane.
 6430. The method of claim 6425, wherein heat is generated by oxidizing molecular hydrogen in at least one heat source.
 6431. The method of claim 6425, wherein heat is generated by electricity produced from wind power.
 6432. The method of claim 6425, wherein heat is generated from electrical power.
 6433. The method of claim 6425, wherein the heat sources form an array of heat sources.
 6434. The method of claim 6425, further comprising heating at least a portion of the selected section of the formation to greater than about 600° C.
 6435. The method of claim 6425, wherein the produced mixture is produced from a production wellbore, and further comprising controlling the heat from one or more heat sources such that the temperature in the formation proximate the production wellbore is at least about 600° C.
 6436. The method of claim 6425, wherein the produced mixture is produced from a production wellbore, and further comprising heating at least a portion of the formation with a heater proximate the production wellbore.
 6437. The method of claim 6425, further comprising recycling at least a portion of the produced molecular hydrogen into the formation.
 6438. The method of claim 6425, wherein the produced mixture comprises methane, and further comprising oxidizing at least a portion of the methane to provide heat to the formation.
 6439. The method of claim 6425, wherein controlling the heat comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 6440. The method of claim 6425, wherein the one or more heat sources comprise one or more electrical heaters powered by a fuel cell, and wherein at least a portion of the molecular hydrogen in the produced mixture is used in the fuel cell.
 6441. The method of claim 6425, further comprising controlling a pressure within at least a majority of the selected section of the formation.
 6442. The method of claim 6425, further comprising controlling the heat such that an average heating rate of the selected section is less than about 3° C. per day during pyrolysis.
 6443. The method of claim 6425, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.
 6444. The method of claim 6425, wherein at least 50% by volume of the produced mixture comprises molecular hydrogen.
 6445. The method of claim 6425, wherein less than about 3.3×10⁻⁸ kg CO₂ is produced for every Joule of energy in the produced mixture.
 6446. The method of claim 6425, wherein less than about 1.6×10⁻¹⁰ kg CO₂ is produced for every Joule of energy in the produced mixture.
 6447. The method of claim 6425, wherein less than about 3.3×10⁻¹⁰ kg CO₂ is produced for every Joule of energy in the produced mixture.
 6448. The method of claim 6425, wherein the produced mixture is produced from a production wellbore, and further comprising controlling the heat from one or more heat sources such that the temperature in the formation proximate the production wellbore is at least about 500° C.
 6449. The method of claim 6425, wherein the produced mixture comprises methane and molecular hydrogen, and further comprising: separating at least a portion of the molecular hydrogen from the produced mixture; and providing at least a portion of the separated mixture to at least one of the one or more heat sources for use as fuel.
 6450. The method of claim 6425, wherein the produced mixture comprises methane and molecular hydrogen, and further comprising: separating at least a portion of the molecular hydrogen from the produced mixture; and providing at least some of the molecular hydrogen to a fuel cell to generate electricity.
 6451. A method for producing methane from a relatively permeable formation in situ while minimizing production of CO₂, comprising: providing heat from one or more heat sources to at least one portion of the formation such that CO₂ production is minimized; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; producing a mixture comprising methane from the formation; and controlling the heat from the one or more heat sources to enhance production of methane.
 6452. The method of claim 6451, wherein the heat provided from at least one of the one or more heat source is transferred to at least a portion of the formation substantially by conduction.
 6453. The method of claim 6451, wherein at least one of the one or more of the heat sources comprises a heater.
 6454. The method of claim 6451, wherein controlling the heat comprises controlling a temperature proximate the production wellbore at or above a decomposition temperature of ethane.
 6455. The method of claim 6451, wherein heat is generated by oxidizing methane in at least one heat source.
 6456. The method of claim 6451, wherein heat is generated by electricity produced from wind power.
 6457. The method of claim 6451, wherein heat is generated from electrical power.
 6458. The method of claim 6451, wherein the heat sources form an array of heat sources.
 6459. The method of claim 6451, further comprising heating at least a portion of the selected section of the formation to greater than about 400° C.
 6460. The method of claim 6451, wherein the produced mixture is produced from a production wellbore, and further comprising controlling the heat from one or more heat sources such that the temperature in the formation proximate the production wellbore is at least about 400° C.
 6461. The method of claim 6451, wherein the produced mixture is produced from a production wellbore, and further comprising heating at least a portion of the formation with a heater proximate the production wellbore.
 6462. The method of claim 6451, further comprising recycling at least a portion of the produced methane into the formation.
 6463. The method of claim 6451, wherein the produced mixture comprises methane, and further comprising oxidizing at least a portion of the methane to provide heat to the formation.
 6464. The method of claim 6451, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 6465. The method of claim 6451, wherein controlling the heat comprises maintaining a temperature within the selected section within a pyrolysis temperature range.
 6466. The method of claim 6451, wherein the one or more heat sources comprise one or more electrical heaters powered by a fuel cell, and wherein at least a portion of the molecular hydrogen in the produced mixture is used in the fuel cell.
 6467. The method of claim 6451, further comprising controlling a pressure within at least a majority of the selected section of the formation.
 6468. The method of claim 6451, further comprising controlling the heat such that an average heating rate of the selected section is less than about 3° C. per day during pyrolysis.
 6469. The method of claim 6451, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.
 6470. The method of claim 6451, wherein less than about 8.4×10⁻⁸ kg CO₂ is produced for every Joule of energy in the produced mixture.
 6471. The method of claim 6451, wherein less than about 7.4×10⁻⁸ kg CO₂ is produced for every Joule of energy in the produced mixture.
 6472. The method of claim 6451, wherein less than about 5.6×10⁻⁸ kg CO₂ is produced for every Joule of energy in the produced mixture.
 6473. A method for upgrading hydrocarbons in a relatively permeable formation, comprising: providing heat from one or more heat sources to a portion of the formation; allowing the heat to transfer from the first portion to a selected section of the formation; providing hydrocarbons to the selected section; and producing a mixture from the formation, wherein the mixture comprises hydrocarbons that were provided to the selected section and upgraded in the formation.
 6474. The method of claim 6473, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6475. The method of claim 6473, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6476. The method of claim 6473, wherein at least one of the one or more of the heat sources comprises a heater.
 6477. The method of claim 6473, wherein the provided hydrocarbons comprise heavy hydrocarbons.
 6478. The method of claim 6473, wherein the provided hydrocarbons comprise naphtha.
 6479. The method of claim 6473, wherein the provided hydrocarbons comprise asphaltenes.
 6480. The method of claim 6473, wherein the provided hydrocarbons comprise crude oil.
 6481. The method of claim 6473, wherein the provided hydrocarbons comprise surface mined tar from relatively permeable formations.
 6482. The method of claim 6473 wherein the provided hydrocarbons comprise an emulsion produced from a relatively permeable formation, and further comprising providing the produced emulsion to the first portion after a temperature in the selected section is greater than about a pyrolysis temperature.
 6483. The method of claim 6473, further comprising providing steam to the selected section.
 6484. The method of claim 6473, further comprising: producing formation fluids from the formation; separating the produced formation fluids into one or more components; and wherein the provided hydrocarbons comprise at least one of the one or more components.
 6485. The method of claim 6473, further comprising: providing steam to the selected section, wherein the provided hydrocarbons are mixed with the steam; and controlling an amount of steam such that a residence time of the provided hydrocarbons within the selected section is controlled.
 6486. The method of claim 6473, wherein the produced mixture comprises upgraded hydrocarbons, and further comprising controlling a residence time of the provided hydrocarbons within the selected section to control a molecular weight distribution within the upgraded hydrocarbons.
 6487. The method of claim 6473, wherein the produced mixture comprises upgraded hydrocarbons, and further comprising controlling a residence time of the provided hydrocarbons in the selected section to control an API gravity of the upgraded hydrocarbons.
 6488. The method of claim 6473, further comprising steam cracking in at least a portion of the selected section.
 6489. The method of claim 6473, wherein the provided hydrocarbons are produced from a second portion of the formation.
 6490. The method of claim 6473, further comprising allowing some of the provided hydrocarbons to crack in the formation to generate upgraded hydrocarbons.
 6491. The method of claim 6473, further comprising controlling a temperature of the first portion of the formation by controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.
 6492. The method of claim 6473, further comprising controlling a pressure within at least a majority of the selected section of the formation.
 6493. The method of claim 6473, wherein a temperature in the first portion is greater than about a pyrolysis temperature.
 6494. The method of claim 6473, further comprising: controlling the heat such that a temperature of the first portion is greater than about a pyrolysis temperature of hydrocarbons; and producing at least some of the provided hydrocarbons from the first portion of the formation.
 6495. The method of claim 6473, further comprising producing at least some of the provided hydrocarbons from a second portion of the formation.
 6496. The method of claim 6473, further comprising: controlling the heat such that a temperature of a second portion is less than about a pyrolysis temperature of hydrocarbons; and producing at least some of the provided hydrocarbons from the second portion of the formation.
 6497. The method of claim 6473, further comprising producing at least some of the provided hydrocarbons from a second portion of the formation and wherein a temperature of the second portion is about an ambient temperature of the formation.
 6498. The method of claim 6473, wherein the upgraded hydrocarbons are produced from a production well and wherein the heat is controlled such that the upgraded hydrocarbons can be produced from the formation as a vapor.
 6499. A method for producing methane from a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; “20 ”allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing hydrocarbon fluids to at least the selected section of the formation; and producing mixture comprising methane from the formation.
 6500. The method of claim 6499, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6501. The method of claim 6499, wherein at least one of the one or more of the heat sources comprises a heater.
 6502. The method of claim 6499, further comprising controlling heat from at least one of the heat sources to enhance production of methane from the hydrocarbon fluids.
 6503. The method of claim 6499, further comprising controlling a temperature within at least a selected section in a range to from greater than about 400° C. to less than about 600° C.
 6504. The method of claim 6499, further comprising cooling the mixture to inhibit further reaction of the methane.
 6505. The method of claim 6499, further comprising controlling at least some condition in the formation to enhance production of methane.
 6506. The method of claim 6499, further comprising adding water to the formation.
 6507. The method of claim 6499, further comprising separating at least a portion of the methane from the mixture and recycling at least some of the separated mixture to the formation.
 6508. The method of claim 6499, further comprising cracking the hydrocarbon fluids to form methane.
 6509. The method of claim 6499, wherein the mixture is produced from the formation through a production well, and wherein the heat is controlled such that the mixture can be produced from the formation as a vapor.
 6510. The method of claim 6499, wherein the mixture is produced from the formation through a production well, and further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.
 6511. The method of claim 6499, wherein the mixture is produced from the formation through a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture.
 6512. A method for hydrotreating a fluid in a heated formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; providing a fluid to the selected section; controlling a H₂ partial pressure in the selected section of the formation; hydrotreating at least some of the fluid in the selected section; and producing a mixture comprising hydrotreated fluids from the formation.
 6513. The method of claim 6512, wherein the mixture is produced from the formation when a partial pressure of hydrogen in the selected section is at least about 0.5 bars absolute.
 6514. The method of claim 6512, wherein the heat provided from at least one of the one or more heat source is transferred to at least a portion of the formation substantially by conduction.
 6515. The method of claim 6512, wherein at least one of the one or more of the heat sources comprises a heater.
 6516. The method of claim 6512, further comprising providing hydrogen to the selected section of the formation.
 6517. The method of claim 6512, further comprising controlling the heat such that a temperature within the selected section is in a range from about 200° C. to about 450° C.
 6518. The method of claim 6512, wherein the provided fluid comprises an olefin.
 6519. The method of claim 6512, wherein the provided fluid comprises pitch.
 6520. The method of claim 6512, wherein the provided fluid comprises oxygenated compounds.
 6521. The method of claim 6512, wherein the provided fluid comprises sulfur containing compounds.
 6522. The method of claim 6512, wherein the provided fluid comprises nitrogen containing compounds.
 6523. The method of claim 6512, wherein the provided fluid comprises crude oil.
 6524. The method of claim 6512, wherein the provided fluid comprises synthetic crude oil.
 6525. The method of claim 6512, wherein the produced mixture comprises a hydrocarbon mixture.
 6526. The method of claim 6512, wherein the produced mixture comprises less than about 1% by weight ammonia.
 6527. The method of claim 6512, wherein the produced mixture comprises less than about 1% by weight hydrogen sulfide.
 6528. The method of claim 6512, wherein the produced mixture comprises less than about 1% oxygenated compounds.
 6529. The method of claim 6512, further comprising producing the mixture from the formation through a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.
 6530. A method for producing hydrocarbons from a heated formation in situ, comprising: providing heat from one or more heat sources to at least one portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that at least some of the selected section comprises a temperature profile; providing a hydrocarbon mixture to the selected section; separating the hydrocarbon mixture into one or more mixtures of components; and producing the one or more mixtures of components from one or more production wells.
 6531. The method of claim 6530, wherein the heat provided from at least one of the one or more heat source is transferred to at least a portion of the formation substantially by conduction.
 6532. The method of claim 6530, wherein the one or more of the heat sources comprise heaters.
 6533. The method of claim 6530, wherein at least one of the one or more mixtures is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6534. The method of claim 6530, further comprising controlling a pressure within at least a majority of the selected section.
 6535. The method of claim 6530, wherein the temperature profile extends horizontally through the formation.
 6536. The method of claim 6530, wherein the temperature profile extends vertically through the formation.
 6537. The method of claim 6530, wherein the selected section comprises a spent formation.
 6538. The method of claim 6530, wherein the production well comprises a plurality of production wells placed at various distances from at least one of the one or more heat sources along the temperature gradient zone.
 6539. The method of claim 6530, wherein the production well comprises a first production well and a second production well, further comprising: positioning the first production well at a first distance from a heat source of the one or more heat sources; positioning the second production well at a second distance from the heat source of the one or more heat sources; producing a first component of the one or more portions from the first production well; and producing a second component of the one or more portions from the second production well.
 6540. The method of claim 6530, further comprising heating a wellbore of the production well to inhibit condensation of at least the one component within the wellbore.
 6541. The method of claim 6530, wherein the one or more components comprise hydrocarbons.
 6542. The method of claim 6530, wherein separating the one or more components further comprises: producing a low molecular weight component of the one or more components from the formation; allowing a high molecular weight component of the one or more components to remain within the formation; providing additional heat to the formation; and producing at least some of the high molecular weight component.
 6543. The method of claim 6530, further comprising producing at least the one component from the formation through a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.
 6544. A method of utilizing heat of a heated formation, comprising: placing a conduit in the formation,; allowing heat from the formation to transfer to at least a portion of the conduit; generating a region of reaction in the conduit; allowing a material to flow through the region of reaction; reacting at least some of the material in the region of reaction; and producing a mixture from the conduit.
 6545. The method of claim 6544, wherein a conduit input is located separately from a conduit output.
 6546. The method of claim 6544, wherein the conduit is configured to inhibit contact between the material and the formation.
 6547. The method of claim 6544, wherein the conduit comprises a u-shaped conduit, and further comprising placing the u-shaped conduit within a heater well in the heated formation.
 6548. The method of claim 6544, wherein the material comprises a first hydrocarbon and wherein the first hydrocarbon reacts to form a second hydrocarbon.
 6549. The method of claim 6544, wherein the material comprises water.
 6550. The method of claim 6544, wherein the produced mixture comprises hydrocarbons.
 6551. A method for storing fluids within a relatively permeable formation, comprising: providing a barrier to a portion of the formation to form an in situ storage area, wherein at least a portion of the in situ storage area has previously undergone an in situ conversion process, and wherein migration of fluids into or out of the storage area is inhibited; providing a material to the in situ storage area; storing at least some of the provided fluids within the in situ storage area; and wherein one or more conditions of the in situ storage area inhibits reaction within the material.
 6552. The method of claim 6551, further comprising producing at least some of the stored material from the in situ storage area.
 6553. The method of claim 6551, further comprising producing at least some of the stored material from the in situ storage area as a liquid.
 6554. The method of claim 6551, further comprising producing at least some of the stored material from the in situ storage area as a gas.
 6555. The method of claim 6551, wherein the stored material is a solid, and further comprising: providing a solvent to the in situ storage area; allowing at least a portion of the stored material to dissolve; and producing at least some of the dissolved material from the in situ storage area.
 6556. The method of claim 6551, wherein the material comprises inorganic compounds.
 6557. The method of claim 6551, wherein the material comprises organic compounds.
 6558. The method of claim 6551, wherein the material comprises hydrocarbons.
 6559. The method of claim 6551, wherein the material comprises formation fluids.
 6560. The method of claim 6551, wherein the material comprises synthesis gas.
 6561. The method of claim 6551, wherein the material comprises a solid.
 6562. The method of claim 6551, wherein the material comprises a liquid.
 6563. The method of claim 6551, wherein the material comprises a gas.
 6564. The method of claim 6551, wherein the material comprises natural gas.
 6565. The method of claim 6551, wherein the material comprises compressed air.
 6566. The method of claim 6551, wherein the material comprises compressed air, and wherein the compressed air is used as a supplement for electrical power generation.
 6567. The method of claim 6551, further comprising: producing at least some of the material from the in situ treatment area through a production well; and heating at least a portion of a wellbore of the production well to inhibit condensation of the material within the wellbore.
 6568. The method of claim 6551, wherein the in situ conversion process comprises pyrolysis.
 6569. The method of claim 6551, wherein the in situ conversion process comprises synthesis gas generation.
 6570. The method of claim 6551, wherein the in situ conversion process comprises solution mining.
 6571. A method of filtering water within a relatively permeable formation comprising: providing water to at least a portion of the formation, wherein the portion has previously undergone an in situ conversion process, and wherein the water comprises one or more components; removing at least one of the one or more components from the provided water; and producing at least some of the water from the formation.
 6572. The method of claim 6571, wherein at least one of the one or more components comprises a dissolved cation, and further comprising: converting at least some of the provided water to steam; allowing at least some of the dissolved cation to remain in the portion of the formation; and producing at least a portion of the steam from the formation.
 6573. The method of claim 6571, wherein the portion of the formation is above the boiling point temperature of the provided water at a pressure of the portion, wherein at least one of the one or more components comprises mineral cations, and wherein the provided water is converted to steam such that the mineral cations are deposited within the formation.
 6574. The method of claim 6571, further comprising converting at least a portion of the provided water into steam and wherein at least one of the one or more components is separated from the water as the provided water is converted into steam.
 6575. The method of claim 6571, wherein a temperature of the portion of the formation is greater than about 90° C., and further comprising sterilizing at least some of the provided water within the portion of the formation.
 6576. The method of claim 6571, wherein a temperature within the portion is less than about a boiling temperature of the provided water at a fluid pressure of the portion.
 6577. The method of claim 6571, further comprising remediating at least the one portion of the formation.
 6578. The method of claim 6571, wherein the one or more components comprise cations.
 6579. The method of claim 6571, wherein the one or more components comprise calcium.
 6580. The method of claim 6571, wherein the one or more components comprise magnesium.
 6581. The method of claim 6571, wherein the one or more components comprise a microorganism.
 6582. The method of claim 6571, wherein the converted portion of the formation further comprises a pore size such that at least one of the one or more components is removed from the provided water.
 6583. The method of claim 6571, wherein the converted portion of the formation adsorbs at least one of the one or more components in the provided water.
 6584. The method of claim 6571, wherein the provided water comprises formation water.
 6585. The method of claim 6571, wherein the in situ conversion process comprises pyrolysis.
 6586. The method of claim 6571, wherein the in situ conversion process comprises synthesis gas generation.
 6587. The method of claim 6571, wherein the in situ conversion process comprises solution mining.
 6588. A method for sequestering carbon dioxide in a relatively permeable formation, comprising: providing carbon dioxide to a portion of the formation, wherein the portion has previously undergone an in situ conversion process; providing a fluid to the portion; allowing at least some of the provided carbon dioxide to contact the fluid in the portion; and precipitating carbonate compounds.
 6589. The method of claim 6588, wherein providing a solution to the portion comprises allowing groundwater to flow into the portion.
 6590. The method of claim 6588, wherein the solution comprises one or more dissolved ions.
 6591. The method of claim 6588, wherein the solution comprises a solution obtained from a formation aquifer.
 6592. The method of claim 6588, wherein the solution comprises a man-made industrial solution.
 6593. The method of claim 6588, wherein the solution comprises agricultural run-off.
 6594. The method of claim 6588, wherein the solution comprises seawater.
 6595. The method of claim 6588, wherein the solution comprises a brine solution.
 6596. The method of claim 6588, further comprising controlling a temperature within the portion.
 6597. The method of claim 6588, further comprising controlling a pressure within the portion.
 6598. The method of claim 6588, further comprising removing at least some of the solution from the formation.
 6599. The method of claim 6588, further comprising removing at least some of the solution from the formation and recycling at least some of the removed solution into the formation.
 6600. The method of claim 6588, further comprising providing a buffering compound to the solution.
 6601. The method of claim 6588, further comprising: providing the solution to the formation; and allowing at least some of the solution to migrate through the formation to increase a contact time between the solution and the provided carbon dioxide.
 6602. The method of claim 6588, wherein the solution is provided to the formation after carbon dioxide has been provided to the formation.
 6603. The method of claim 6588, further comprising providing heat to the portion.
 6604. The method of claim 6588, wherein providing carbon dioxide to a portion of the formation comprises providing carbon dioxide to a first location, wherein providing a solution to the portion comprises providing the solution to a second location, and wherein the first location is downdip of the second location.
 6605. The method of claim 6588, wherein allowing at least some of the provided carbon dioxide to contact the solution in the portion comprises allowing at least some of the carbon dioxide and at least some of the solution to migrate past each other.
 6606. The method of claim 6588, wherein the solution is provided to the formation prior to providing the carbon dioxide, and further comprising providing at least some of the carbon dioxide to a location positioned proximate a lower surface of the portion such that some of the carbon dioxide may migrate up through the portion.
 6607. The method of claim 6588, wherein the solution is provided to the formation prior to providing the carbon dioxide, and further comprising allowing at least some carbon dioxide to migrate through the portion.
 6608. The method of claim 6588, further comprising: providing heat to the portion, wherein the portion comprises a temperature greater than about a boiling point of the solution; vaporizing at least some of the solution; producing a fluid from the formation.
 6609. The method of claim 6588, further comprising decreasing leaching of metals from the formation into groundwater.
 6610. A method of treating a relatively permeable formation, comprising: injecting a recovery fluid into a portion of the formation; allowing heat within the recovery fluid, and heat from one or more heat sources, to transfer to a selected section of the formation, wherein the selected section comprises hydrocarbons; mobilizing at least some of the hydrocarbons within the selected section; and producing a mixture from the formation.
 6611. The method of claim 6610, wherein the portion has been previously produced.
 6612. The method of claim 6610, wherein the portion has previously undergone an in situ conversion process.
 6613. The method of claim 6610, further comprising upgrading at least some hydrocarbons within the selected section to decrease a viscosity of the hydrocarbons.
 6614. The method of claim 6610, wherein the produced mixture comprises hydrocarbons having an average API gravity greater than about 25°.
 6615. The method of claim 6610, further comprising vaporizing at least some of the hydrocarbons within the selected section.
 6616. The method of claim 6610, wherein the recovery fluid comprises water.
 6617. The method of claim 6610, wherein the recovery fluid comprises hydrocarbons.
 6618. The method of claim 6610, wherein the mixture comprises pyrolyzation fluids.
 6619. The method of claim 6610, wherein the mixture comprises hydrocarbons.
 6620. The method of claim 6610, wherein the mixture is produced from a production well and further comprising controlling a pressure such that a fluid pressure proximate to the production well is less than about a fluid pressure proximate to a location where the fluid is injected.
 6621. The method of claim 6610, further comprising: monitoring a composition of the produced mixture; and controlling a fluid pressure in at least a portion of the formation to control the composition of the produced mixture.
 6622. The method of claim 6610, further comprising pyrolyzing at least some of the hydrocarbons within the selected section of the formation.
 6623. The method of claim 6610, wherein the average temperature of the selected section is between about 275° C. to about 375° C., and wherein a fluid pressure of the recovery fluid is between about 60 bars to about 220 bars, and wherein the recovery fluid comprises steam.
 6624. The method of claim 6610, further comprising controlling pressure within the selected section such that a fluid pressure within the selected section is at least about a hydrostatic pressure of a surrounding portion of the formation.
 6625. The method of claim 6610, further comprising controlling pressure within the selected section such that a fluid pressure within the selected section is greater than about a hydrostatic pressure of a surrounding portion of the formation.
 6626. The method of claim 6610, wherein a depth of the selected section is between about 300 m to about 400 m.
 6627. The method of claim 6610, wherein the mixture comprises pyrolysis products.
 6628. The method of claim 6610, further comprising vaporizing at least some of the hydrocarbons within the selected section and wherein the vaporized hydrocarbons comprise hydrocarbons having a carbon number greater than about 1 and a carbon number less than about
 4. 6629. The method of claim 6610, further comprising allowing the injected recovery fluid to contact a substantial portion of a volume of the selected section.
 6630. The method of claim 6610, wherein the recovery fluid comprises steam, and wherein the pressure of the injected steam is at least about 90 bars, and wherein the temperature of the injected steam is at least about 300° C.
 6631. The method of claim 6610, further comprising upgrading at least a portion of the hydrocarbons within the selected section of the formation such that a viscosity of the portion of the hydrocarbons is decreased.
 6632. The method of claim 6610, further comprising separating the recovery fluid from pyrolyzation fluid and distilled hydrocarbons in the formation, and further comprising producing the pyrolyzation fluid and distilled hydrocarbons.
 6633. The method of claim 6610, wherein the transfer fluid and vaporized hydrocarbons are separated with membranes.
 6634. The method of claim 6610, wherein the selected section comprises a first selected section and a second selected section and further comprising: mobilizing at least some of the hydrocarbons within the selected first section of the formation; allowing at least some of the mobilized hydrocarbons to flow from the selected first section of the formation to a selected second section of the formation, and wherein the selected second section comprises hydrocarbons; and heating at least a portion of the formation using one ore more heat sources; pyrolyzing at least some of the hydrocarbons within the selected second section of the formation; and producing a mixture from the formation.
 6635. The method of claim 6610, wherein a residence time of the recovery fluid in the formation is greater than about one month and less than about six months.
 6636. The method of claim 6610, further comprising: allowing the recovery fluid to soak in the selected section of the formation for a selected time period; and producing at least a portion of the recovery fluid from the formation.
 6637. A method of treating relatively permeable formation in situ, comprising: injecting a recovery fluid into the formation; providing heat from one or more heat sources to the formation; allowing the heat to transfer from one or more of the heat sources to a selected section of the formation, wherein the selected section comprises hydrocarbons; mobilizing at least some of the hydrocarbons; and producing a mixture from the formation, wherein the produced mixture comprises hydrocarbons having an average API gravity greater than about 25°.
 6638. The method of claim 6637, wherein the heat provided from at least one of the one or more heat sources is transferred to at least a portion of the formation substantially by conduction.
 6639. The method of claim 6637, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6640. The method of claim 6637, wherein at least one of the one or more of the heat sources comprises a heater.
 6641. The method of claim 6637, further comprising pyrolyzing at least some of the hydrocarbons within selected section.
 6642. The method of claim 6637, further comprising pyrolyzing at least some of the mobilized hydrocarbons.
 6643. The method of claim 6637, wherein the recovery fluid comprises water.
 6644. The method of claim 6637, wherein the recovery fluid comprises hydrocarbons.
 6645. The method of claim 6637, wherein the mixture comprises pyrolyzation fluids.
 6646. The method of claim 6637, wherein the mixture comprises steam.
 6647. The method of claim 6637, wherein a pressure is controlled such that a fluid pressure proximate to one or more of the heat sources is greater than a fluid pressure proximate to a location where the fluid is produced.
 6648. The method of claim 6637, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.
 6649. The method of claim 6637, wherein the heat is provided such that an average temperature in the selected section ranges from approximately about 270° C. to about 375° C.
 6650. The method of claim 6637, further comprising: monitoring a composition of the produced mixture; and controlling a pressure in at least a portion of the formation to control the composition of the produced mixture.
 6651. The method of claim 6650, wherein the pressure is controlled by a valve proximate to a location where the mixture is produced.
 6652. The method of claim 6650, wherein the pressure is controlled such that pressure proximate to one or more of the heat sources is greater than a pressure proximate to a location where the mixture is produced.
 6653. The method of claim 6637, wherein a residence time of the recovery fluid in the formation is less than about one month to greater than about six months.
 6654. The method of claim 6637, further comprising: allowing the recovery fluid to soak in the selected section of the formation for a selected time period; and producing at least a portion of the recovery fluid from the formation.
 6655. A method of treating a relatively permeable formation in situ, comprising: injecting a recovery fluid into a formation; allowing the recovery fluid to migrate through at least a portion of the formation, wherein a size of a selected section increases as a recovery fluid front migrates through an untreated portion of the formation, and wherein the selected section is a portion of the formation treated by the recovery fluid; allowing heat from the recovery fluid to transfer heat to the selected section, wherein the heat from the recovery fluid, and heat from one or more heat sources, pyrolyzes at least some of the hydrocarbons within the selected section of the formation; allowing the heat from the recovery fluid or one or more heat sources to mobilize at least some of the hydrocarbons at the recovery fluid front; allowing the heat from the recovery fluid, and heat from one or more heat sources, to pyrolyze at least a portion of the hydrocarbons in the mobilized fluid; and producing a mixture from the formation.
 6656. The method of claim 6655, wherein one or more heat sources are heaters.
 6657. The method of claim 6655, wherein the mixture is produced as a mixture of vapors.
 6658. The method of claim 6655, wherein an average temperature of the selected section is about 300° C., and wherein the recovery fluid pressure is about 90 bars.
 6659. The method of claim 6655, wherein the mobilized hydrocarbons flow substantially parallel to the recovery fluid front.
 6660. The method of claim 6655, wherein the mixture is produced from an upper portion of the formation.
 6661. The method of claim 6655, wherein a portion of the recovery fluid condenses and migrates due to gravity to a lower portion of the selected section, and further comprising producing a portion of the condensed recovery fluid.
 6662. The method of claim 6655, wherein the pyrolyzed fluid migrates to an upper portion of the formation.
 6663. The method of claim 6655, wherein the mixture comprises pyrolyzation fluids.
 6664. The method of claim 6655, wherein the mixture comprises recovery fluid.
 6665. The method of claim 6655, wherein the recovery fluid comprises steam.
 6666. The method of claim 6655, wherein the recovery fluid is injected through one or more injection wells.
 6667. The method of claim 6666, wherein the one or more injection wells are located substantially horizontally in the formation.
 6668. The method of claim 6666, wherein the one or more injection wells are located substantially vertically in the formation.
 6669. The method of claim 6655, wherein the mixture is produced through one or more production wells.
 6670. The method of claim 6669, wherein the one or more production wells are located substantially horizontally in the formation.
 6671. The method of claim 6655, wherein the mixture is produced through a heat source wellbore.
 6672. The method of claim 6655, wherein the produced mixture comprises hydrocarbons having an average API gravity at least about 25°.
 6673. The method of claim 6655, wherein at least about 20% of the hydrocarbons in the selected first section and the selected second section are pyrolyzed.
 6674. The method of claim 6655, further comprising providing heat from one or more heat sources to at least one portion of the formation.
 6675. The method of claim 6655, wherein the heat from the one or more heat sources vaporizes water injected into the formation.
 6676. The method of claim 6655, wherein the heat from the one or more heat sources heats recovery fluid in the formation, wherein the recovery fluid comprises steam.
 6677. The method of claim 6655, wherein the one or more heat sources comprise electrical heaters.
 6678. The method of claim 6655, wherein the one or more heat sources comprise flame distributed combustors.
 6679. The method of claim 6655, wherein the one or more heat sources comprise natural distributed combustors.
 6680. The method of claim 6655, further comprising separating recovery fluid from pyrolyzation fluids in the formation.
 6681. The method of claim 6655, further comprising producing liquid hydrocarbons from the formation, and further comprising reinjecting the produced liquid hydrocarbons into the formation.
 6682. The method of claim 6655, further comprising producing a liquid mixture from the formation, wherein the produced liquid mixture comprises substantially of condensed recovery fluid.
 6683. The method of claim 6655, further comprising separating condensed recovery fluid from liquid hydrocarbons in the formation, and further comprising producing the condensed recovery fluid from the formation.
 6684. The method of claim 6655, wherein the recovery fluid is injected into regions of relatively high water saturation.
 6685. The method of claim 6655, wherein injected recovery fluid contacts a substantial portion of a volume of the selected section.
 6686. The method of claim 6655, wherein the recovery fluid comprises steam, and wherein the pressure of the injected steam is at least about 90 bars, and wherein the temperature of the injected steam is at least about 300° C.
 6687. The method of claim 6655, wherein at least a portion of sulfur is retained in the formation.
 6688. The method of claim 6655, wherein the heat from recovery fluid partially upgrades at least a portion of the hydrocarbons within the selected section of the formation, and wherein the partial upgrading reduces the viscosity of the portion of the hydrocarbons.
 6689. The method of claim 6655, further comprising separating the recovery fluid from pyrolyzation fluid and distilled hydrocarbons in the formation, and further comprising producing the pyrolyzation fluid and distilled hydrocarbons.
 6690. The method of claim 6655, wherein the recovery fluid and vaporized hydrocarbons are separated with membranes.
 6691. The method of claim 6655, wherein a residence time of the recovery fluid in the formation is less than about one month to greater than about six months.
 6692. The method of claim 6655, further comprising: allowing the heat transfer fluid to soak in the selected section of the formation for a selected time period; and producing at least a portion of the heat transfer fluid from the formation.
 6693. A method of recovering methane from a relatively permeable formation, comprising: providing heat from one or more heat sources to at least one portion of the formation, wherein the portion comprises methane; allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and producing fluids from the formation, wherein the produced fluids comprise methane.
 6694. The method of claim 6693, further comprising providing a barrier to at least a segment of the formation.
 6695. The method of claim 6693, further comprising: providing a refrigerant to a plurality of barrier wells to form a low temperature zone around the portion of the formation; lowering a temperature within the low temperature zone to a temperature less than about a freezing temperature of water; and removing water from the portion of the formation.
 6696. The method of claim 6693, wherein an average temperature of the selected section is less than about 100° C.
 6697. The method of claim 6693, wherein an average temperature of the selected section is less than about a boiling point of water at an ambient pressure in the formation.
 6698. The method of claim 6693, wherein an amount of methane produced from the formation is in a range from about 1 m³ of methane per ton of formation to about 30 m³ of methane per ton of formation.
 6699. The method of claim 6693, wherein the methane produced from the formation is used as fuel for an in situ treatment of a relatively permeable formation.
 6700. The method of claim 6693, wherein the methane produced from the formation is used to generate power for electrical heater wells.
 6701. The method of claim 6693, wherein the methane produced from the formation is used as fuel for gas fired heater wells.
 6702. The method of claim 6693, further comprising providing carbon dioxide to the treatment area and allowing at least a portion of the methane to desorb.
 6703. The method of claim 6693, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6704. The method of claim 6693, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6705. The method of claim 6693, wherein the one or more of the heat sources comprise heaters.
 6706. A method of recovering methane from a relatively permeable formation, comprising: providing a barrier to a portion of the formation, wherein the portion comprises methane; removing the water from the portion; and producing fluids from the formation, wherein the produced fluids comprise methane.
 6707. The method of claim 6706, wherein removing water from the portion comprises pumping at least some water from the formation.
 6708. The method of claim 6706, wherein the barrier inhibits migration of fluids into or out of a treatment area of the formation.
 6709. The method of claim 6706, further comprising decreasing a fluid pressure within the portion and allowing at least some of the methane to desorb.
 6710. The method of claim 6706, further comprising providing carbon dioxide to the portion and allowing at least some of the methane to desorb.
 6711. The method of claim 6706, wherein providing a barrier comprises: providing refrigerant to a plurality of freeze wells to form a low temperature zone around the portion; and lowering a temperature within the low temperature zone to a temperature less than about a freezing temperature of water.
 6712. The method of claim 6706, wherein providing a barrier comprises providing refrigerant to a plurality of freeze wells to form a frozen barrier zone and wherein the frozen barrier zone hydraulically isolates the treatment area from a surrounding portion of the formation.
 6713. The method of claim 6706, further comprising: providing heat from one or more heat sources to at least one portion of the formation; and allowing the heat to transfer from the one or more heat sources to a selected section of the formation.
 6714. The method of claim 6706, wherein an average temperature of the selected section is less than about 100° C.
 6715. The method of claim 6706, wherein an average temperature of the selected section is less than about a boiling point of water at an ambient pressure in the formation.
 6716. A method of shutting-in an in situ treatment process in a relatively permeable formation, comprising: terminating heating from one or more heat sources providing heat to a portion of the formation; monitoring a pressure in at least a portion of the formation; controlling the pressure in the portion of the formation such that the pressure is maintained approximately below a fracturing or breakthrough pressure of the formation.
 6717. The method of claim 6716, wherein monitoring the pressure in the formation comprises detecting fractures with passive acoustic monitoring.
 6718. The method of claim 6716, wherein controlling the pressure in the portion of the formation comprises: producing hydrocarbon vapor from the formation when the pressure is greater than approximately the fracturing or breakthrough pressure of the formation; and allowing produced hydrocarbon vapor to oxidize at a surface of the formation.
 6719. The method of claim 6716, wherein controlling the pressure in the portion of the formation comprises: producing hydrocarbon vapor from the formation when the pressure is greater than approximately the fracturing or breakthrough pressure of the formation; and storing at least a portion of the produced hydrocarbon vapor.
 6720. A method of shutting-in an in situ treatment process in a relatively permeable formation, comprising: terminating heating from one or more heat sources providing heat to a portion of the formation; producing hydrocarbon vapor from the formation; and injecting at least a portion of the produced hydrocarbon vapor into a portion of a storage formation.
 6721. The method of claim 6720, wherein the storage formation comprises a spent formation.
 6722. The method of claim 6721, wherein an average temperature of the portion of the spent formation is less than about 100° C.
 6723. The method of claim 6721, wherein a substantial portion of condensable compounds in the injected hydrocarbon vapor condense in the spent formation.
 6724. The method of claim 6720, wherein the storage formation comprises a relatively high temperature formation, and further comprising converting a substantial portion of injected hydrocarbons into coke and molecular hydrogen.
 6725. The method of claim 6724, wherein the average temperature of the portion of the relatively high temperature formation is greater than about 300° C.
 6726. The method of claim 6724, further comprising: producing at least a portion of the H₂ from the relatively high temperature formation; and allowing the produced molecular hydrogen to oxidize at a surface of the relatively high temperature formation.
 6727. The method of claim 6720, wherein the storage formation comprises a depleted formation.
 6728. The method of claim 6727, wherein the depleted formation comprises an oil field.
 6729. The method of claim 6727, wherein the depleted formation comprises a gas field.
 6730. The method of claim 6727, wherein the depleted formation comprises a water zone comprising seal and trap integrity.
 6731. A method of producing a soluble compound from a soluble compound containing formation, comprising: providing heat from one or more heat sources to at least a portion of a hydrocarbon containing layer; producing a mixture comprising hydrocarbons from the formation; using heat from the formation, heat from the mixture produced from the formation, or a component from the mixture produced from the formation to adjust a quality of a first fluid; providing the first fluid to a soluble compound containing formation; and producing a second fluid comprising a soluble compound from the soluble compound containing formation.
 6732. The method of claim 6731, further comprising pyrolyzing at least some hydrocarbons in the hydrocarbon containing layer.
 6733. The method of claim 6731, further comprising dissolving the soluble compound in the soluble compound containing formation.
 6734. The method of claim 6731, wherein the soluble compound comprises a phosphate.
 6735. The method of claim 6731, wherein the soluble compound comprises alumina.
 6736. The method of claim 6731, wherein the soluble compound comprises a metal.
 6737. The method of claim 6731, wherein the soluble compound comprises a carbonate.
 6738. The method of claim 6731, further comprising separating at least a portion of the soluble compound from the second fluid.
 6739. The method of claim 6731, further comprising separating at least a portion of the soluble compound from the second fluid, and then recycling a portion of the second fluid into the soluble compound containing formation.
 6740. The method of claim 6731, wherein heat is provided from the heated formation, or from the mixture produced from the formation, in the form of hot water or steam.
 6741. The method of claim 6731, wherein the quality of the first fluid that is adjusted is pH.
 6742. The method of claim 6731, wherein the quality of the first fluid that is adjusted is temperature.
 6743. The method of claim 6731, further comprising adding a dissolving compound to the first fluid that facilitates dissolution of the soluble compound in the soluble containing formation.
 6744. The method of claim 6731, wherein CO₂ produced from the hydrocarbon containing layer is used to adjust acidity of the solution.
 6745. The method of claim 6731, wherein the soluble compound containing formation is at a different depth than the portion of the hydrocarbon containing layer.
 6746. The method of claim 6731, wherein heat from the portion of the hydrocarbon containing layer migrates and heats at least a portion of the soluble compound containing formation.
 6747. The method of claim 6731, wherein the soluble compound containing formation is at a different location than the portion of the hydrocarbon containing layer.
 6748. The method of claim 6731, further comprising using openings for providing the heat sources, and further comprising using at least a portion of these openings to provide the first fluid to the soluble compound containing formation.
 6749. The method of claim 6731, further comprising providing the solution to the soluble compound containing formation in one or more openings that were previously used to (a) provide heat to the hydrocarbon containing layer, or (b) produce the mixture from the hydrocarbon containing layer.
 6750. The method of claim 6731, further comprising providing heat to the hydrocarbon containing layer, or producing the mixture from the hydrocarbon containing layer, using one or more openings that were previously used to provide a solution to a soluble compound containing formation.
 6751. The method of claim 6731, further comprising: separating at least a portion of the soluble compound from the second fluid; providing heat to at least the portion of the soluble compound; and wherein the provided heat is generated in part using one or more products of an in situ conversion process.
 6752. The method of claim 6731, further comprising producing the second fluid when a partial pressure of hydrogen in the portion of the hydrocarbon containing layer is at least about 0.5 bars absolute.
 6753. The method of claim 6731, wherein the heat provided from at least one heat source is transferred to at least a part of the hydrocarbon containing layer substantially by conduction.
 6754. The method of claim 6731, wherein one or more of the heat sources comprise heaters.
 6755. The method of claim 6731, wherein the soluble compound containing formation comprises nahcolite.
 6756. The method of claim 6731, wherein greater than about 10% by weight of the soluble compound containing formation comprises nahcolite.
 6757. The method of claim 6731, wherein the soluble compound containing formation comprises dawsonite.
 6758. The method of claim 6731, wherein greater than about 2% by weight of the soluble compound containing formation comprises dawsonite.
 6759. The method of claim 6731, wherein the first fluid comprises steam.
 6760. The method of claim 6731, wherein the first fluid comprises steam, and further comprising providing heat to the soluble compound containing formation by injecting the steam into the formation.
 6761. The method of claim 6731, wherein the soluble compound containing formation is heated and then the first fluid is provided to the formation.
 6762. A method of treating a relatively permeable formation in situ, comprising: providing heat to at least a portion of the formation; allowing the heat to transfer from at least the portion to a selected section of the formation such that dissociation of carbonate minerals is inhibited; injecting a first fluid into the selected section; producing a second fluid from the formation; and conducting an in situ conversion process in the selected section.
 6763. The method of claim 6762, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6764. The method of claim 6762, wherein the heat is provided from at least one heat source, and wherein the heat is transferred to at least the portion of the formation substantially by conduction.
 6765. The method of claim 6762, wherein the in situ conversion process comprises: providing additional heat to a least a portion of the formation; pyrolyzing at least some hydrocarbons in the portion; and producing a mixture from the formation.
 6766. The method of claim 6762, wherein the selected section comprises nahcolite.
 6767. The method of claim 6762, wherein the selected section comprises dawsonite.
 6768. The method of claim 6762, wherein the selected section comprises trona.
 6769. The method of claim 6762, wherein the selected section comprises gaylussite.
 6770. The method of claim 6762, wherein the selected section comprises carbonates.
 6771. The method of claim 6762, wherein the selected section comprises carbonate phosphates.
 6772. The method of claim 6762, wherein the selected section comprises carbonate chlorides.
 6773. The method of claim 6762, wherein the selected section comprises silicates.
 6774. The method of claim 6762, wherein the selected section comprises borosilicates.
 6775. The method of claim 6762, wherein the selected section comprises halides.
 6776. The method of claim 6762, wherein the first fluid comprises a pH greater than about
 7. 6777. The method of claim 6762, wherein the first fluid comprises a temperature less than about 110° C.
 6778. The method of claim 6762, wherein the portion has previously undergone an in situ conversion process prior to the injection of the first fluid.
 6779. The method of claim 6762, wherein the second fluid comprises hydrocarbons.
 6780. The method of claim 6762, wherein the second fluid comprises hydrocarbons, and further comprising: fragmenting at least some of the portion prior to providing the first fluid; generating hydrocarbons; and providing at least some of the second fluid to a surface treatment unit, wherein the second fluid comprises at least some of the generated hydrocarbons.
 6781. The method of claim 6762, further comprising removing mass from the selected section in the second fluid.
 6782. The method of claim 6762, further comprising removing mass from the selected section in the second fluid such that a permeability of the selected section increases.
 6783. The method of claim 6762, further comprising removing mass from the selected section in the second fluid and decreasing a heat transfer time in the selected section.
 6784. The method of claim 6762, further comprising controlling the heat such that the selected section has a temperature of above about 120° C.
 6785. The method of claim 6762, wherein the selected section comprises nahcolite, and further comprising controlling the heat such that the selected section has a temperature less than about a dissociation temperature of nahcolite.
 6786. The method of claim 6762, wherein the second fluid comprises soda ash, and further comprising removing at least a portion of the soda ash from the second fluid as sodium carbonate.
 6787. The method of claim 6762, wherein the in situ conversion process comprises pyrolyzing hydrocarbon containing material in the selected section.
 6788. The method of claim 6762, wherein the second fluid comprises nahcolite, and further comprising: separating at least a portion of the nahcolite from the second fluid; providing heat to at least some of the separated nahcolite to form a sodium carbonate solution; providing at least some of the sodium carbonate solution to at least the portion of the formation; and producing a third fluid comprising alumina from the formation.
 6789. The method of claim 6762, further comprising providing a barrier to at least the portion of the formation to inhibit migration of fluids into or out of the portion.
 6790. The method of claim 6762, further comprising controlling the heat such that a temperature within the selected section of the portion is less than about 100° C.
 6791. The method of claim 6762, further comprising: providing additional heat from the one or more heat sources to at least the portion of the formation; allowing the additional heat to transfer from at least the portion to the selected section of the formation; pyrolyzing at least some hydrocarbons within the selected section of the formation; producing a mixture from the formation; reducing a temperature of the selected section of the formation injecting a third fluid into the selected section; and producing a fourth fluid from the formation.
 6792. The method of claim 6791, wherein the third fluid comprises water.
 6793. The method of claim 6791, wherein the third fluid comprises steam.
 6794. The method of claim 6791, wherein the fourth fluid comprises a metal.
 6795. The method of claim 6791, wherein the fourth fluid comprises a mineral.
 6796. The method of claim 6791, wherein the fourth fluid comprises aluminum.
 6797. The method of claim 6791, wherein the fourth fluid comprises a metal, and fiber comprising producing the metal from the second fluid.
 6798. The method of claim 6791, further comprising producing a non-hydrocarbon material from the fourth fluid.
 6799. The method of claim 6762, wherein the first fluid comprises steam.
 6800. The method of claim 6762, wherein the second fluid comprises a metal.
 6801. The method of claim 6762, wherein the second fluid comprises a mineral.
 6802. The method of claim 6762, wherein the second fluid comprises aluminum.
 6803. The method of claim 6762, wherein the second fluid comprises a metal, and further comprising separating the metal from the second fluid.
 6804. The method of claim 6762, further comprising producing a non-hydrocarbon material from the second fluid.
 6805. The method of claim 6762, wherein greater than about 10% by weight of the selected section comprises nahcolite.
 6806. The method of claim 6762, wherein greater than about 2% by weight of the selected section comprises dawsonite.
 6807. The method of claim 6762, wherein the provided heat comprises waste heat from another portion of the formation.
 6808. The method of claim 6762, wherein the first fluid comprises steam, and further comprising providing heat to the formation by injecting the steam into the formation.
 6809. The method of claim 6762, further comprising providing heat to the formation by injecting the first fluid into the formation.
 6810. The method of claim 6762, further comprising providing heat to the formation by injecting the first fluid into the formation, wherein the first fluid is at a temperature above about 90° C.
 6811. The method of claim 6762, further comprising controlling a temperature of the selected section while injecting the first fluid, wherein the temperature is less than about a temperature at which nahcolite will dissociate.
 6812. The method of claim 6762, wherein a temperature within the selected section is less than about 90° C. prior to injecting the first fluid to the formation.
 6813. The method of claim 6762, further comprising providing a barrier substantially surrounding the selected section such that the barrier inhibits the flow of water into the formation.
 6814. A method of treating a relatively permeable formation in situ, comprising: injecting a first fluid into the selected section; producing a second fluid from the formation; providing heat from one or more heat sources to at least a portion of the formation, wherein the heat is provided after production of the second fluid has begun; allowing the heat to transfer from at least a portion of the formation; pyrolyzing at least some hydrocarbons within the selected section; and producing a mixture from the formation.
 6815. The method of claim 6814, wherein the selected section comprises nahcolite.
 6816. The method of claim 6814, wherein the selected section comprises dawsonite.
 6817. The method of claim 6814, wherein the selected section comprises trona.
 6818. The method of claim 6814, wherein the selected section comprises gaylussite.
 6819. The method of claim 6814, wherein the selected section comprises carbonates.
 6820. The method of claim 6814, wherein the selected section comprises carbonate phosphates.
 6821. The method of claim 6814, wherein the selected section comprises carbonate chlorides.
 6822. The method of claim 6814, wherein the selected section comprises silicates.
 6823. The method of claim 6814, wherein the selected section comprises borosilicates.
 6824. The method of claim 6814, wherein the selected section comprises halides.
 6825. The method of claim 6814, wherein the first fluid comprises a pH greater than about
 7. 6826. The method of claim 6814, wherein the first fluid comprises a temperature less than about 110° C.
 6827. The method of claim 6814, wherein the second fluid comprises hydrocarbons.
 6828. The method of claim 6814, wherein the second fluid comprises hydrocarbons, and further comprising: fragmenting at least some of the portion prior to providing the first fluid; generating hydrocarbons; and providing at least some of the second fluid to a surface treatment unit, wherein the second fluid comprises at least some of the generated hydrocarbons.
 6829. The method of claim 6814, further comprising removing mass from the selected section in the second fluid.
 6830. The method of claim 6814, further comprising removing mass from the selected section in the second fluid such that a permeability of the selected section increases.
 6831. The method of claim 6814, further comprising removing mass from the selected section in the second fluid and decreasing a heat transfer time in the selected section.
 6832. The method of claim 6814, further comprising controlling the heat such that the selected section has a temperature of above about 270° C.
 6833. The method of claim 6814, wherein the second fluid comprises soda ash, and further comprising removing at least a portion of the soda ash from the second fluid as sodium carbonate.
 6834. The method of claim 6814, wherein the second fluid comprises nahcolite, and further comprising: separating at least a portion of the nahcolite from the second fluid; providing heat to at least some of the separated nahcolite to form a sodium carbonate solution; providing at least some of the sodium carbonate solution to at least the portion of the formation; and producing a third fluid comprising alumina from the formation.
 6835. The method of claim 6814, further comprising providing a barrier to at least the portion of the formation to inhibit migration of fluids into or out of the portion.
 6836. The method of claim 6814, wherein the first fluid comprises steam.
 6837. The method of claim 6814, wherein the second fluid comprises a metal.
 6838. The method of claim 6814, wherein the second fluid comprises a mineral.
 6839. The method of claim 6814, wherein the second fluid comprises aluminum.
 6840. The method of claim 6814, wherein the second fluid comprises a metal, and further comprising separating the metal from the second fluid.
 6841. The method of claim 6814, further comprising producing a non-hydrocarbon material from the second fluid.
 6842. The method of claim 6814, wherein greater than about 10% by weight of the selected section comprises nahcolite.
 6843. The method of claim 6814, wherein greater than about 2% by weight of the selected section comprises dawsonite.
 6844. The method of claim 6814, wherein at least some of the provided heat comprises waste heat from another portion of the formation.
 6845. The method of claim 6814, wherein the first fluid comprises steam, and further comprising providing heat to the formation by injecting the steam into the formation.
 6846. The method of claim 6814, further comprising providing heat to the formation by injecting the first fluid into the formation.
 6847. The method of claim 6814, further comprising providing heat to the formation by injecting the first fluid into the formation, wherein the first fluid is at a temperature above about 90° C.
 6848. The method of claim 6814, further comprising controlling a temperature of the selected section while injecting the first fluid, wherein the temperature is less than about a temperature at which nahcolite will dissociate.
 6849. The method of claim 6814, further comprising providing a barrier substantially surrounding the selected section such that the barrier inhibits the flow of water into the formation.
 6850. The method of claim 6814, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.
 6851. The method of claim 6814, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6852. The method of claim 6814, wherein the one or more of the heat sources comprise heaters.
 6853. A method of solution mining alumina from an in situ relatively permeable formation, comprising: providing heat from one or more heat sources to a least a portion of the formation; pyrolyzing at least some hydrocarbons in the portion; and producing a mixture from the formation providing a brine solution to a portion of the formation; and producing a mixture comprising alumina from the formation.
 6854. The method of claim 6853, wherein the selected section comprises dawsonite.
 6855. The method of claim 6853, further comprising: separating at least a portion of the alumina from the mixture; and providing heat to at least the portion of the alumina to generate aluminum.
 6856. The method of claim 6853, further comprising: separating at least a portion of the alumina from the mixture; providing heat to at least the portion of the alumina to generate aluminum; and wherein the provided heat is generated in part using one or more products of an in situ conversion process.
 6857. The method of claim 6853, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 6858. The method of claim 6853, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6859. The method of claim 6853, wherein one or more of the heat sources comprise heaters.
 6860. A method of treating a relatively permeable formation in situ, comprising: allowing a temperature of a portion of the formation to decrease, wherein the portion has previously undergone an in situ conversion process; injecting a first fluid into the selected section; and producing a second fluid from the formation.
 6861. The method of claim 6860, wherein the in situ conversion process comprises: providing heat to a least a portion of the formation; pyrolyzing at least some hydrocarbons in the portion; and producing a mixture from the formation.
 6862. The method of claim 6860, wherein the first fluid comprises water.
 6863. The method of claim 6860, wherein the second fluid comprises a metal.
 6864. The method of claim 6860, wherein the second fluid comprises a mineral.
 6865. The method of claim 6860, wherein the second fluid comprises aluminum.
 6866. The method of claim 6860, wherein the second fluid comprises a metal, and further comprising producing the metal from the second fluid.
 6867. The method of claim 6860, wherein comprising producing a non-hydrocarbon material from the second fluid.
 6868. The method of claim 6860, wherein the selected section comprises nahcolite.
 6869. The method of claim 6860, wherein greater than about 10% by weight of the selected section comprises nahcolite.
 6870. The method of claim 6860, wherein the selected section comprises dawsonite.
 6871. The method of claim 6860, wherein greater than about 2% by weight of the selected section comprises dawsonite.
 6872. The method of claim 6860, wherein the provided heat comprises waste heat from another portion of the formation.
 6873. The method of claim 6860, wherein the first fluid comprises steam.
 6874. The method of claim 6860, wherein the first fluid comprises steam, and further comprising providing heat to the formation by injecting the steam into the formation.
 6875. The method of claim 6860, wherein comprising providing heat to the formation by injecting the first fluid into the formation.
 6876. The method of claim 6860, further comprising providing heat to the formation by injecting the first fluid into the formation, wherein the first fluid is at a temperature above about 90° C.
 6877. The method of claim 6860, wherein the reduced temperature of the selected section is less than about 90° C.
 6878. The method of claim 6860, wherein an average richness of at least the portion of the selected section is greater than about 0.10 liters per kilogram.
 6879. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to a first section of the formation such that the heat provided to the first section pyrolyzes at least some hydrocarbons within the first section; providing heat from one or more heat sources to a second section of the formation such that the heat provided to the second section pyrolyzes at least some hydrocarbons within the second section; inducing at least a portion of the hydrocarbons from the second section to flow into the first section; and producing a mixture from the first section, wherein the produced mixture comprises at least some pyrolyzed hydrocarbons from the second section.
 6880. The method of claim 6879, wherein a portion of the first section comprises a first permeability, wherein a portion of the second section comprises a second permeability, and wherein the first permeability is greater than about the second permeability.
 6881. The method of claim 6879, wherein a portion of the first section comprises a first permeability, wherein a portion of the second section comprises a second permeability, and wherein the first permeability is less than about the second permeability.
 6882. The method of claim 6879, wherein the second section is substantially adjacent to the first section.
 6883. The method of claim 6879, further comprising providing heat to a third section of the formation such that the heat provided to the third section pyrolyzes at least some hydrocarbons in the third section and inducing a portion of the hydrocarbons from the third section to flow into the first section.
 6884. The method of claim 6883, wherein the third section is substantially adjacent to the first section.
 6885. The method of claim 6879, further comprising: providing heat from one or more heat sources to a third section of the formation such that the heat provided to the third section pyrolyzes at least some hydrocarbons in the third section; and inducing a portion of the hydrocarbons from the third section to flow into the first section through the second section.
 6886. The method of claim 6885, wherein the third section is substantially adjacent to the second section.
 6887. The method of claim 6879, further comprising maintaining a pressure in the formation below about 150 bars absolute.
 6888. The method of claim 6879, further comprising inhibiting production of the produced mixture until at least some hydrocarbons in the formation have been pyrolyzed.
 6889. The method of claim 6879, further comprising producing at least some hydrocarbons from the first section before providing heat to the second section.
 6890. The method of claim 6879, further comprising producing at least some hydrocarbons from the first section before a temperature in the second section reaches a pyrolysis temperature.
 6891. The method of claim 6879, further comprising maintaining a pressure within the formation below a selected pressure by producing at least some hydrocarbons from the formation.
 6892. The method of claim 6879, further comprising producing the produced mixture through at least one production well in or proximate the first section.
 6893. The method of claim 6879, further comprising producing at least some hydrocarbons through at least one production well in or proximate the second section.
 6894. The method of claim 6879, further comprising controlling the heat provided to the first section and the second section such that conversion of heavy hydrocarbons into light hydrocarbons within the formation is controlled.
 6895. The method of claim 6894, wherein controlling the heat provided to the first section and the second section comprises adjusting heat output of at least one of the heat sources that heats the first section.
 6896. The method of claim 6894, wherein controlling the heat provided to the first section and the second section comprises adjusting heat output of at least one of the heat sources that heats the second section.
 6897. The method of claim 6879, wherein one or more heat sources provide heat to the first section of the formation and the second section of the formation.
 6898. The method of claim 6879, wherein a first set of one or more heat sources provides heat to the first section and a second set of one or more heat sources provides heat to the second section.
 6899. The method of claim 6879, further comprising controlling the heat provided to the first section and the second section to produce a desired characteristic in the produced mixture.
 6900. The method of claim 6899, wherein controlling the heat provided to the first section and the second section comprises adjusting heat output of at least one of the heat sources that heats the first section.
 6901. The method of claim 6899, wherein controlling the heat provided to the first section and the second section comprises adjusting heat output of at least one of the heat sources that heats the first section.
 6902. The method of claim 6899, wherein the desired characteristic in the produced mixture comprises an API gravity of the produced mixture.
 6903. The method of claim 6899, wherein the desired characteristic in the produced mixture comprises a production rate of the produced mixture.
 6904. The method of claim 6899, wherein the desired characteristic in the produced mixture comprises a weight percentage of light hydrocarbons in the produced mixture.
 6905. The method of claim 6879, wherein the produced mixture comprises an API gravity of greater than about 20°.
 6906. The method of claim 6879, wherein the produced mixture comprises an acid number less than about
 1. 6907. The method of claim 6879, wherein greater than about 50% by weight of the initial mass of hydrocarbons in the formation is produced.
 6908. The method of claim 6879, wherein at least a portion of the first section is above a pyrolysis temperature of the hydrocarbons.
 6909. The method of claim 6908, wherein the pyrolysis temperature is at least about 250° C.
 6910. The method of claim 6879, wherein the heat sources that heat the first section comprise a spacing between heated portions of the heat sources of less than about 25 m.
 6911. The method of claim 6879, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 6912. The method of claim 6879, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6913. The method of claim 6879, wherein one or more of the heat sources comprise heaters.
 6914. The method of claim 6879, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 6915. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to a first section of the formation such that the heat provided to the first section pyrolyzes at least some hydrocarbons within the first section; providing heat from one or more heat sources to a second section of the formation such that the heat provided to the second section pyrolyzes at least some hydrocarbons within the second section; inducing at least a portion of the hydrocarbons from the second section to flow into the first section; inhibiting production of a mixture until at least some hydrocarbons in the formation have been pyrolyzed; and producing the mixture from the first section, wherein the produced mixture comprises at least some pyrolyzed hydrocarbons from the second section.
 6916. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to a first section of the formation such that the heat provided to the first section reduces the viscosity of at least some heavy hydrocarbons within the first section; providing heat from one or more heat sources to a second section of the formation such that the heat provided to the second section reduces the viscosity of at least some heavy hydrocarbons within the second section; inducing a portion of the heavy hydrocarbons from the second section to flow into the first section; pyrolyzing at least some of the heavy hydrocarbons within the first section; and producing a mixture from the first section, wherein the produced mixture comprises at least some pyrolyzed hydrocarbons.
 6917. The method of claim 6916, wherein the second section is substantially adjacent to the first section.
 6918. The method of claim 6916, further comprising producing a mixture from the first section of the formation, wherein the mixture comprises at least some heavy hydrocarbons.
 6919. The method of claim 6916, further comprising producing the mixture from the first section through a production well in or proximate the first section and pyrolyzing at least some of the heavy hydrocarbons within the production well.
 6920. The method of claim 6916, further comprising pyrolyzing at least some hydrocarbons within the second section.
 6921. The method of claim 6916, further comprising providing heat to a third section of the formation such that the heat provided to the third section reduces the viscosity of at least some heavy hydrocarbons in the third section, and inducing a portion of the heavy hydrocarbons from the third section to flow into the first section.
 6922. The method of claim 6921, wherein the third section is substantially adjacent to the first section.
 6923. The method of claim 6916, further comprising: providing heat from one or more heat sources to a third section of the formation such that the heat provided to the third section reduces the viscosity of at least some heavy hydrocarbons in the third section; inducing a portion of the heavy hydrocarbons from the third section to flow into the second section; pyrolyzing at least some of the heavy hydrocarbons within the second section; and producing a mixture from the second section, wherein the produced mixture comprises at least some pyrolyzed hydrocarbons.
 6924. The method of claim 6923, wherein the third section is substantially adjacent to the second section.
 6925. The method of claim 6916, further comprising: providing heat from one or more heat sources to a third section of the formation such that the heat provided to the third section reduces the viscosity of at least some heavy hydrocarbons in the third section; and inducing a portion of the heavy hydrocarbons from the third section to flow into the first section through the second section.
 6926. The method of claim 6925, wherein the third section is substantially adjacent to the second section.
 6927. The method of claim 6916, wherein one or more heat sources provide heat to the first section of the formation and the second section of the formation.
 6928. The method of claim 6916, wherein a first set of one or more heat sources provides heat to the first section and a second set of one or more heat sources provides heat to the second section.
 6929. The method of claim 6916, further comprising controlling the heat provided to the first section and the second section such that conversion of heavy hydrocarbons into light hydrocarbons within the first section is controlled.
 6930. The method of claim 6929, wherein controlling the heat provided to the first section and the second section comprises adjusting heat output of at least one of the heat sources that heats the first section.
 6931. The method of claim 6929, wherein controlling the heat provided to the first section and the second section comprises adjusting heat output of at least one of the heat sources that heats the second section.
 6932. The method of claim 6916, further comprising controlling the heat provided to the first section and the second section to produce a desired characteristic in the produced mixture.
 6933. The method of claim 6932, wherein controlling the heat provided to the first section and the second section comprises adjusting heat output of at least one of the heat sources that heats the first section.
 6934. The method of claim 6932, wherein controlling the heat provided to the first section and the second section comprises adjusting heat output of at least one of the heat sources that heats the first section.
 6935. The method of claim 6932, wherein the desired characteristic in the produced mixture comprises an API gravity of the produced mixture.
 6936. The method of claim 6932, wherein the desired characteristic in the produced mixture comprises a weight percentage of light hydrocarbons in the produced mixture.
 6937. The method of claim 6916, further comprising producing at least about 70% of an initial volume in place from the formation.
 6938. The method of claim 6916, wherein the produced mixture comprises an API gravity of greater than about 20°.
 6939. The method of claim 6916, wherein the produced mixture comprises an acid number less than about
 1. 6940. The method of claim 6916, wherein at least a portion of the first section is above a pyrolysis temperature of the hydrocarbons.
 6941. The method of claim 6940, wherein the pyrolysis temperature is at least about 250° C.
 6942. The method of claim 6916, wherein a spacing between heated sections of at least two heat sources is less than about 25 m.
 6943. The method of claim 6916, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 6944. The method of claim 6916, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6945. The method of claim 6916, wherein one or more of the heat sources comprise heaters.
 6946. The method of claim 6916, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 6947. A method for treating a relatively permeable formation in situ, comprising: providing heat to at least a portion of the formation; producing heavy hydrocarbons from a first section of the relatively permeable formation; inducing heavy hydrocarbons from a second section of the formation to flow into the first section of the formation; producing a portion of the second section heavy hydrocarbons from the first section of the formation; inducing heavy hydrocarbons from a third section of the formation to flow into the second section of the formation; and producing a portion of the third section heavy hydrocarbons from the second section of the formation or the first section of the formation.
 6948. The method of claim 6947, wherein greater than 50% by weight of the initial mass of hydrocarbons in a portion of the formation selected for treatment are produced.
 6949. The method of claim 6947, further comprising pyrolyzing at least some of the second section heavy hydrocarbons in the first section.
 6950. The method of claim 6947, further comprising pyrolyzing at least some of the third section heavy hydrocarbons in the second section or the first section.
 6951. The method of claim 6947, further comprising producing at least about 70% of an initial volume in place from the formation.
 6952. The method of claim 6947, further comprising producing hydrocarbons when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 6953. The method of claim 6947, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6954. The method of claim 6947, wherein one or more of the heat sources comprise heaters.
 6955. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the relatively permeable formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat reduces the viscosity of at least some hydrocarbons within the selected section; providing a gas to the selected section of the formation, wherein the gas produces a flow of at least some hydrocarbons within the selected section; and producing a mixture from the selected section.
 6956. The method of claim 6955, further comprising controlling a pressure within the selected section such that the pressure is maintained below about 150 bars absolute.
 6957. The method of claim 6955, further comprising controlling a temperature within the selected section to maintain the temperature within the selected section below a pyrolysis temperature of the hydrocarbons.
 6958. The method of claim 6957, further comprising maintaining an average temperature within the selected section above about 50° C. and below about 210° C.
 6959. The method of claim 6955, wherein providing the gas to the selected section comprises injecting the gas such that the gas sweeps hydrocarbons within the selected section, and wherein greater than about 50% by weight of the initial mass of hydrocarbons is produced from the selected section.
 6960. The method of claim 6955, further comprising producing at least about 70% of an initial volume in place from the selected section.
 6961. The method of claim 6955, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 6962. The method of claim 6955, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about 5, and wherein the produced mixture comprises an API gravity of at least about
 15. 6963. The method of claim 6955, further comprising providing the gas through one or more injection wells in the selected section.
 6964. The method of claim 6955, further comprising providing the gas through one or more injection wells in the selected section and controlling a pressure within the selected section by controlling an injection rate into at least one injection well.
 6965. The method of claim 6955, further comprising providing the gas through one or more injection wells in the formation and controlling a pressure within the selected section by controlling a location for injecting the gas within the formation.
 6966. The method of claim 6955, further comprising producing the mixture through one or more production wells in or proximate the formation.
 6967. The method of claim 6955, further comprising controlling a pressure within the selected section through one or more production wells in or proximate the formation.
 6968. The method of claim 6955, further comprising controlling a temperature within the selected section while controlling a pressure within the selected section.
 6969. The method of claim 6955, further comprising creating a path for flow of hydrocarbons along a length of at least one heat source in the selected section.
 6970. The method of claim 6969, wherein the path along the length of at least one heat source extends between an injection well and a production well.
 6971. The method of claim 6969, wherein a heat source is tuned off after the path for flow along the heat source is created.
 6972. The method of claim 6955, wherein the gas increases a flow of hydrocarbons within the formation.
 6973. The method of claim 6955, further comprising increasing a pressure in the selected section with the provided gas.
 6974. The method of claim 6955, wherein a spacing between heated sections of at least two sources is less than about 50 m and greater than about 5 m.
 6975. The method of claim 6955, wherein the gas comprises carbon dioxide.
 6976. The method of claim 6955, wherein the gas comprises nitrogen.
 6977. The method of claim 6955, wherein the gas comprises steam.
 6978. The method of claim 6955, wherein the gas comprises water, and wherein the water forms steam in the formation.
 6979. The method of claim 6955, wherein the gas comprises methane.
 6980. The method of claim 6955, wherein the gas comprises gas produced from the formation.
 6981. The method of claim 6955, further comprising providing the gas through at least one injection well placed substantially vertically in the formation, and producing the mixture through a heat source placed substantially horizontally in the formation.
 6982. The method of claim 6981, further comprising selectively limiting a temperature proximate a selected portion of a wellbore of the heat source to inhibit coke formation at or near the selected portion, and producing the mixture through perforations in the selected portion of the wellbore.
 6983. The method of claim 6955, further comprising allowing heat to transfer to the selected section such that the provided heat pyrolyzes at least some hydrocarbons within the selected section.
 6984. The method of claim 6955, further comprising controlling the transfer of heat from the one or more heat sources and controlling the flow of provided gas such that the flow of hydrocarbons within the selected section is controlled.
 6985. The method of claim 6955, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 6986. The method of claim 6955, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 6987. The method of claim 6955, wherein one or more of the heat sources comprise heaters.
 6988. The method of claim 6955, wherein the produced mixture comprises an acid number less than about
 1. 6989. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the relatively permeable formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat reduces the viscosity of at least some hydrocarbons within the selected section; providing a gas to the selected section of the formation, wherein the gas produces a flow of at least some hydrocarbons within the selected section; controlling a pressure within the selected section such that the pressure is maintained below about 150 bars absolute; and producing a mixture from the selected section.
 6990. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the relatively permeable formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section; producing a mixture of hydrocarbons from the selected section; and controlling production of the mixture to adjust the time that at least some hydrocarbons are exposed to pyrolysis temperatures in the formation in order to produce hydrocarbons of a selected quality in the mixture.
 6991. The method of claim 6990, further comprising inhibiting production of hydrocarbons from the formation until at least some hydrocarbons have been pyrolyzed.
 6992. The method of claim 6990, wherein the selected quality comprises a selected minimum API gravity.
 6993. The method of claim 6990, wherein the selected quality comprises an API gravity of at least about
 200. 6994. The method of claim 6990, wherein the selected quality comprises a selected maximum weight percentage of heavy hydrocarbons.
 6995. The method of claim 6990, wherein the selected quality comprises a mean carbon number that is less than
 12. 6996. The method of claim 6990, wherein the produced mixture comprises an acid number less than about
 1. 6997. The method of claim 6990, further comprising sampling a test stream of the produced mixture to determine the selected quality of the produced mixture.
 6998. The method of claim 6990, further comprising determining the time that at least some hydrocarbons in the produced mixture are subjected to pyrolysis temperatures using laboratory treatment of formation samples.
 6999. The method of claim 6990, further comprising determining the time that at least some hydrocarbons in the produced mixture are subjected to pyrolysis temperatures using a computer simulation of treatment of the formation.
 7000. The method of claim 6990, further comprising controlling a pressure within the selected section such that the pressure is maintained below a lithostatic pressure of the formation.
 7001. The method of claim 6990, further comprising controlling a pressure within the selected section such that the pressure is maintained below a hydrostatic pressure of the formation.
 7002. The method of claim 6990, further comprising controlling a pressure within the selected section such that the pressure is maintained below about 150 bars absolute.
 7003. The method of claim 6990, further comprising controlling a pressure within the selected section through one or more production wells.
 7004. The method of claim 6990, further comprising controlling a pressure within the selected section through one or more pressure release wells.
 7005. The method of claim 6990, further comprising controlling a pressure within the selected section by producing at least some hydrocarbons from the selected section.
 7006. The method of claim 6990, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7007. The method of claim 6990, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7008. The method of claim 6990, wherein one or more of the heat sources comprise heaters.
 7009. The method of claim 6990, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 7010. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section; selectively limiting a temperature proximate a selected portion of a heat source wellbore to inhibit coke formation at or near the selected portion; and producing at least some hydrocarbons through the selected portion of the heat source wellbore.
 7011. The method of claim 7010, further comprising generating water in the selected portion to inhibit coke formation at or near the selected portion of the heat source wellbore.
 7012. The method of claim 7010, wherein the heat source wellbore is placed substantially horizontally within the selected section.
 7013. The method of claim 7010, wherein selectively limiting the temperature comprises providing less heat at the selected portion of the heat source wellbore than other portions of the heat source wellbore in the selected section.
 7014. The method of claim 7010, wherein selectively limiting the temperature comprises maintaining the temperature proximate the selected portion below pyrolysis temperatures.
 7015. The method of claim 7010, further comprising producing a mixture from the selected section through a production well.
 7016. The method of claim 7010, further comprising providing at least some heat to an overburden section of the heat source wellbore to maintain the produced hydrocarbons in a vapor phase.
 7017. The method of claim 7010, further comprising maintaining a pressure in the selected section below about 150 bars absolute.
 7018. The method of claim 7010, further comprising producing hydrocarbons when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7019. The method of claim 7010, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7020. The method of claim 7010, wherein one or more of the heat sources comprise heaters.
 7021. The method of claim 7010, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 7022. The method of claim 7010, wherein the produced mixture comprises an acid number less than about
 1. 7023. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section; controlling operating conditions at a production well to inhibit coking in or proximate the production well; and producing a mixture from the selected section through the production well.
 7024. The method of claim 7023, wherein controlling the operating conditions at the production well comprises controlling heat output from at least one heat source proximate the production well.
 7025. The method of claim 7023, wherein controlling the operating conditions at the production well comprises reducing or turning off heat provided from at least one of the heat sources for at least part of a time in which the mixture is produced through the production well.
 7026. The method of claim 7023, wherein controlling the operating conditions at the production well comprises increasing or turning on heat provided from at least one of the heat sources to maintain a desired quality in the produced mixture.
 7027. The method of claim 7023, wherein controlling the operating conditions at the production well comprises producing the mixture at a location sufficiently spaced from at least one heat source such that coking is inhibited at the production well.
 7028. The method of claim 7023, further comprising adding steam to the selected section to inhibit coking at the production well.
 7029. The method of claim 7023, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7030. The method of claim 7023, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7031. The method of claim 7023, wherein one or more of the heat sources comprise heaters.
 7032. The method of claim 7023, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 7033. The method of claim 7023, wherein the produced mixture comprises an acid number less than about
 1. 7034. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the relatively permeable formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section; producing a mixture from the selected section; and controlling a quality of the produced mixture by varying a location for producing the mixture.
 7035. The method of claim 7034, wherein varying the location for producing the mixture comprises varying a production location within a production well in or proximate the selected section.
 7036. The method of claim 7035, wherein varying the production location within the production well comprises varying a packing height within the production well.
 7037. The method of claim 7035, wherein varying the production location within the production well comprises varying a location of perforations used to produce the mixture within the production well.
 7038. The method of claim 7034, wherein varying the location for producing the mixture comprises varying a production location along a length of a production wellbore placed in the formation.
 7039. The method of claim 7034, wherein varying the location for producing the mixture comprises varying a location of a production well within the formation.
 7040. The method of claim 7034, wherein varying the location for producing the mixture comprises varying a number of production wells in the formation.
 7041. The method of claim 7034, wherein varying the location for producing the mixture comprises varying a distance between a production well and one or more heat sources.
 7042. The method of claim 7034, further comprising increasing the quality of the produced mixture by producing the mixture from an upper portion of the selected section.
 7043. The method of claim 7034, further comprising increasing a total mass recovery from the selected section by producing the mixture from a lower portion of the selected section.
 7044. The method of claim 7034, further comprising selecting the location for production based on a price characteristic for produced hydrocarbons.
 7045. The method of claim 7044, wherein the price characteristic is determined by multiplying a production rate of the produced mixture at a selected API gravity from the selected section by a price obtainable for selling the produced mixture with the selected API gravity.
 7046. The method of claim 7044, further comprising adjusting the location for production based on a change in the price characteristic.
 7047. The method of claim 7034, wherein the quality of the produced mixture comprises an API gravity of the produced mixture.
 7048. The method of claim 7034, wherein the produced mixture comprises an acid number less than about
 1. 7049. The method of claim 7034, further comprising controlling the quality of the produced mixture by controlling the heat provided from at least one heat source.
 7050. The method of claim 7034, further comprising controlling the quality of the produced mixture such that the produced mixture comprises a selected minimum API gravity.
 7051. The method of claim 7034, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7052. The method of claim 7034, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7053. The method of claim 7034, wherein one or more of the heat sources comprise heaters.
 7054. The method of claim 7034, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 7055. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the relatively permeable formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section; producing a first mixture from a first portion of the selected section; and producing a second mixture from a second portion of the selected section.
 7056. The method of claim 7055, further comprising producing a third mixture from a third portion of the selected section.
 7057. The method of claim 7055, further comprising producing a third mixture from a third portion of the selected section, wherein the first portion is substantially above the second portion, wherein the second portion is substantially above the third portion, and wherein the first mixture is produced, then the second mixture, and then the third mixture.
 7058. The method of claim 7055, wherein the first portion is substantially above the second portion.
 7059. The method of claim 7055, wherein the first portion is substantially below the second portion.
 7060. The method of claim 7055, wherein the first portion is substantially adjacent to the second portion.
 7061. The method of claim 7055, wherein the first mixture comprises an API gravity greater than about 20°.
 7062. The method of claim 7055, wherein the second mixture comprises an API gravity greater than about 20°.
 7063. The method of claim 7055, wherein the first mixture comprises an acid number less than about
 1. 7064. The method of claim 7055, wherein the second mixture comprises an acid number less than about
 1. 7065. The method of claim 7055, wherein the first portion comprises about an upper one-third of the formation.
 7066. The method of claim 7055, wherein the second portion comprises about a lower one-third of the formation.
 7067. The method of claim 7055, wherein the first mixture is produced before the second mixture is produced.
 7068. The method of claim 7055, further comprising producing the first or the second mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7069. The method of claim 7055, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7070. The method of claim 7055, wherein one or more of the heat sources comprise heaters.
 7071. The method of claim 7055, wherein a ratio of energy output of the first or the second produced mixture to energy input into the formation is at least about
 5. 7072. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to a selected section of the formation such that the heat provided to the selected section pyrolyzes at least some hydrocarbons within a lower portion of the formation; and producing a mixture from an upper portion of the formation, wherein the produced mixture comprises at least some pyrolyzed hydrocarbons from the lower portion.
 7073. The method of claim 7072, wherein the produced mixture comprises an API gravity greater than about 15°.
 7074. The method of claim 7072, wherein the produced mixture comprises an acid number less than about
 1. 7075. The method of claim 7072, wherein the upper portion comprises about an upper one-half of the formation.
 7076. The method of claim 7072, wherein the lower portion comprises about a lower one-half of the formation.
 7077. The method of claim 7072, further comprising producing the mixture of hydrocarbons as a vapor.
 7078. The method of claim 7072, further comprising providing heat from one or more heat sources to a selected section of the formation such that the heat provided to the selected section reduces the viscosity of at least some hydrocarbons within the selected section.
 7079. The method of claim 7072, further comprising inducing at least a portion of the hydrocarbons from the lower portion to flow into the upper portion.
 7080. The method of claim 7072, wherein the upper portion and the lower portion are within the selected section.
 7081. The method of claim 7072, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7082. The method of claim 7072, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7083. The method of claim 7072, wherein one or more of the heat sources comprise heaters.
 7084. The method of claim 7072, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 7085. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of a relatively permeable formation; allowing heat to transfer from one or more heat sources to a first selected section of a relatively permeable formation such that the heat reduces the viscosity of at least some hydrocarbons within the first selected section; producing a first mixture from the first selected section; allowing heat to transfer from one or more heat sources to a second selected section of a relatively permeable formation such that the heat pyrolyzes at least some hydrocarbons within the second selected section; producing a second mixture from the second selected section; and blending at least a portion of the first mixture with at least a portion of the second mixture to produce a third mixture comprising a selected property.
 7086. The method of claim 7085, wherein the selected property of the third mixture comprises an API gravity.
 7087. The method of claim 7085, wherein the selected property of the third mixture comprises an API gravity of at least about 10°.
 7088. The method of claim 7085, wherein the selected property of the third mixture comprises a selected viscosity.
 7089. The method of claim 7085, wherein the selected property of the third mixture comprises a viscosity less than about 7500 cs.
 7090. The method of claim 7085, wherein the selected property of the third mixture comprises a density.
 7091. The method of claim 7085, wherein the selected property of the third mixture comprises a density less than about 1 g/cm³.
 7092. The method of claim 7085, wherein the selected property of the third mixture comprises an asphaltene to saturated hydrocarbon ratio of less than about
 1. 7093. The method of claim 7085, wherein the selected property of the third mixture comprises an aromatic hydrocarbon to saturated hydrocarbon ratio of less than about
 4. 7094. The method of claim 7085, wherein asphaltenes are substantially stable in the third mixture at ambient temperature.
 7095. The method of claim 7085, wherein the third mixture is transportable.
 7096. The method of claim 7085, wherein the third mixture is transportable through a pipeline.
 7097. The method of claim 7085, wherein the first mixture comprises an API gravity less than about 15°.
 7098. The method of claim 7085, wherein the second mixture comprises an API gravity greater than about 25°.
 7099. The method of claim 7085, wherein the second mixture comprises an acid number less than about
 1. 7100. The method of claim 7085, further comprising selecting a ratio of the first mixture to the second mixture such that at least about 50% by weight of the initial mass of hydrocarbons in a selected portion of the formation is produced.
 7101. The method of claim 7085, wherein the third mixture comprises less than about 50% by weight of the second mixture.
 7102. The method of claim 7085, wherein the first selected section comprises a depth of at least about 500 m below the surface of a relatively permeable formation.
 7103. The method of claim 7085, wherein the second selected section comprises a depth less than about 500 m below the surface of a relatively permeable formation.
 7104. The method of claim 7085, wherein the first selected section and the second selected section are located in different relatively permeable formations.
 7105. The method of claim 7085, wherein the first selected section and the second selected section are located in different relatively permeable formations, and wherein the different relatively permeable formation are vertically displaced.
 7106. The method of claim 7085, wherein the first selected section and the second selected section are vertically displaced within a single relatively permeable formation.
 7107. The method of claim 7085, wherein the first selected section and the second selected section are substantially adjacent within a single relatively permeable formation.
 7108. The method of claim 7085, wherein blending comprises injecting at least a portion of the second mixture into the first selected section such that the second mixture blends with at least a portion of the first mixture to produce the third mixture in the first selected section.
 7109. The method of claim 7085, wherein blending comprises injecting at least a portion of the second mixture into a production well in the first selected section such that the second mixture blends with at least a portion of the first mixture to produce the third mixture in the production well.
 7110. The method of claim 7085, further comprising producing a mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7111. The method of claim 7085, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7112. The method of claim 7085, wherein one or more of the heat sources comprise heaters.
 7113. The method of claim 7085, wherein a ratio of energy output of the first or the second produced mixture to energy input into the formation is at least about
 5. 7114. A method for treating a relatively permeable formation in situ to produce a blending agent, comprising: providing heat from one or more heat sources to at least a portion of the relatively permeable formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section; producing a blending agent from the selected section; and wherein at least a portion of the blending agent is adapted to blend with a liquid to produce a mixture with a selected property.
 7115. The method of claim 7114, wherein the liquid comprises at least some heavy hydrocarbons.
 7116. The method of claim 7114, wherein the liquid comprises an API gravity below about 15°.
 7117. The method of claim 7114, wherein the liquid is viscous, and wherein a mixture produced by blending at least a portion of the blending agent with the liquid is less viscous than the liquid.
 7118. The method of claim 7114, wherein the selected property of the mixture comprises an API gravity.
 7119. The method of claim 7114, wherein the selected property of the mixture comprises an API gravity of at least about 10°.
 7120. The method of claim 7114, wherein the selected property of the mixture comprises a selected viscosity.
 7121. The method of claim 7114, wherein the selected property of the mixture comprises a viscosity less than about 7500 cs.
 7122. The method of claim 7114, wherein the selected property of the mixture comprises a density.
 7123. The method of claim 7114, wherein the selected property of the mixture comprises a density less than about 1 g/cm³.
 7124. The method of claim 7114, wherein the selected property of the mixture comprises an asphaltene to saturated hydrocarbon ratio of less than about
 1. 7125. The method of claim 7114, wherein the selected property of the mixture comprises an aromatic hydrocarbon to saturated hydrocarbon ratio of less than about
 4. 7126. The method of claim 7114, wherein asphaltenes are substantially stable in the mixture at ambient temperature.
 7127. The method of claim 7114, wherein the mixture is transportable.
 7128. The method of claim 7114, wherein the mixture is transportable through a pipeline.
 7129. The method of claim 7114, wherein the liquid has a viscosity sufficiently high to inhibit economical transport of the liquid over 100 km via a pipeline but the mixture has a reduced viscosity that allows economical transport of the mixture over 100 km via a pipeline.
 7130. The method of claim 7114, further comprising producing the liquid from a second section of a relatively permeable formation and blending the liquid with the blending agent to produce the mixture.
 7131. The method of claim 7114, further comprising producing the liquid from a second section of a relatively permeable formation and blending the liquid with the blending agent to produce the mixture, wherein the mixture comprises less than about 50% by weight of the blending agent.
 7132. The method of claim 7114, further comprising injecting the blending agent into a second section of a relatively permeable formation such that the blending agent blends with the liquid in the second section to produce the mixture.
 7133. The method of claim 7114, further comprising injecting the blending agent into a production well in a second section of a relatively permeable formation such that the blending agent blends with the liquid in the production well to produce the mixture.
 7134. The method of claim 7114, further comprising producing the blending agent when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7135. The method of claim 7114, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7136. The method of claim 7114, wherein one or more of the heat sources comprise heaters.
 7137. The method of claim 7114, wherein a ratio of energy output of the blending agent to energy input into the formation is at least about
 5. 7138. The method of claim 7114, wherein the blending agent comprises an acid number less than about
 1. 7139. A blending agent produced by a method, comprising: providing heat from one or more heat sources to at least a portion of a relatively permeable formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section; and producing the blending agent from the selected section; wherein at least a portion of the blending agent is adapted to blend with a liquid to produce a mixture with a selected property.
 7140. The blending agent of claim 7139, wherein the blending agent comprises an API gravity of at least about 20°.
 7141. The blending agent of claim 7139, wherein the blending agent comprises an acid number less than about
 1. 7142. The blending agent of claim 7139, wherein the blending agent comprises an asphaltene weight percentage less than about 0.5%.
 7143. The blending agent of claim 7139, wherein the blending agent comprises a combined nitrogen, oxygen, and sulfur weight percentage less than about 5%.
 7144. The blending agent of claim 7139, wherein asphaltenes are substantially stable in the mixture at ambient temperature.
 7145. The blending agent of claim 7139, wherein the method further comprises producing the blending agent when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7146. The blending agent of claim 7139, wherein the method further comprises the heat provided from at least one heat source transferring to at least a portion of the formation substantially by conduction.
 7147. The blending agent of claim 7139, wherein the method further comprises one or more of the heat sources comprising heaters.
 7148. The blending agent of claim 7139, wherein the method further comprises a ratio of energy output of the blending agent to energy input into the formation being at least about
 5. 7149. A method for treating a relatively permeable formation in situ, comprising: producing a first mixture from a first selected section of a relatively permeable formation, wherein the first mixture comprises heavy hydrocarbons; providing heat from one or more heat sources to a second selected section of the relatively permeable formation such that the heat pyrolyzes at least some hydrocarbons within the second selected section; producing a second mixture from the second selected section; and blending at least a portion of the first mixture with at least a portion of the second mixture to produce a third mixture comprising a selected property.
 7150. The method of claim 7149, further comprising cold producing the first mixture from the first selected section.
 7151. The method of claim 7149, wherein producing the first mixture from the first selected section comprises producing the first mixture through a production well in or proximate the formation.
 7152. The method of claim 7149, wherein the selected property of the third mixture comprises an API gravity.
 7153. The method of claim 7149, wherein the selected property of the third mixture comprises a selected viscosity.
 7154. The method of claim 7149, wherein the selected property of the third mixture comprises a density.
 7155. The method of claim 7149, wherein the selected property of the third mixture comprises an asphaltene to saturated hydrocarbon ratio of less than about
 1. 7156. The method of claim 7149, wherein the selected property of the third mixture comprises an aromatic hydrocarbon to saturated hydrocarbon ratio of less than about
 4. 7157. The method of claim 7149, wherein asphaltenes are substantially stable in the third mixture at ambient temperature.
 7158. The method of claim 7149, wherein the third mixture is transportable.
 7159. The method of claim 7149, wherein the third mixture is transportable through a pipeline.
 7160. The method of claim 7149, wherein the liquid has a viscosity sufficiently high to inhibit economical transport of the liquid over 100 km via a pipeline but the mixture has a reduced viscosity that allows economical transport of the mixture over 100 km via a pipeline.
 7161. The method of claim 7149, wherein the first mixture comprises an API gravity less than about 15°.
 7162. The method of claim 7149, wherein the second mixture comprises an API gravity greater than about 25°.
 7163. The method of claim 7149, wherein the second mixture comprises an acid number less than about
 1. 7164. The method of claim 7149, wherein the third mixture comprises less than about 50% by weight of the second mixture.
 7165. The method of claim 7149, wherein the first selected section comprises a depth of at least about 500 m below the surface of a relatively permeable formation.
 7166. The method of claim 7149, wherein the second selected section comprises a depth less than about 500 m below the surface of a relatively permeable formation.
 7167. The method of claim 7149, further comprising producing a mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7168. The method of claim 7149, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7169. The method of claim 7149, wherein one or more of the heat sources comprise heaters.
 7170. The method of claim 7149, wherein a ratio of energy output of the second mixture to energy input into the formation is at least about
 5. 7171. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to a selected section of a relatively permeable formation such that the heat pyrolyzes at least some hydrocarbons within the selected section; producing a blending agent from the selected section; and injecting at least a portion of the blending agent into a second section of a relatively permeable formation to produce a mixture having a selected property, wherein the second section comprises at least some heavy hydrocarbons.
 7172. The method of claim 7171, wherein the selected property of the mixture comprises an API gravity.
 7173. The method of claim 7171, wherein the selected property of the mixture comprises an API gravity of at least about 10°.
 7174. The method of claim 7171, wherein the selected property of the mixture comprises a selected viscosity.
 7175. The method of claim 7171, wherein the selected property of the mixture comprises a viscosity less than about 7500 cs.
 7176. The method of claim 7171, wherein the selected property of the mixture comprises a density.
 7177. The method of claim 7171, wherein the selected property of the mixture comprises a density less than about 1 g/cm³.
 7178. The method of claim 7171, wherein the selected property of the mixture comprises an asphaltene to saturated hydrocarbon ratio of less than about
 1. 7179. The method of claim 7171, wherein the selected property of the mixture comprises an aromatic hydrocarbon to saturated hydrocarbon ratio of less than about
 4. 7180. The method of claim 7171, wherein asphaltenes are substantially stable in the mixture at ambient temperature.
 7181. The method of claim 7171, wherein the mixture is transportable.
 7182. The method of claim 7171, wherein the mixture is transportable through a pipeline.
 7183. The method of claim 7171, wherein second section comprises heavy hydrocarbons having an API gravity less than about 15°.
 7184. The method of claim 7171, wherein the blending agent comprises an API gravity greater than about 25°.
 7185. The method of claim 7171, wherein the blending agent comprises an acid number less than about
 1. 7186. The method of claim 7171, wherein the mixture comprises less than about 50% by weight of the blending agent.
 7187. The method of claim 7171, wherein the selected section comprises a depth of at least about 500 m below the surface of a relatively permeable formation.
 7188. The method of claim 7171, wherein the second section comprises a depth less than about 500 m below the surface of a relatively permeable formation.
 7189. The method of claim 7171, wherein the selected section and the second section are located in different relatively permeable formations.
 7190. The method of claim 7171, wherein the selected section and the second section are located in different relatively permeable formations, and wherein the different relatively permeable formation are vertically displaced.
 7191. The method of claim 7171, wherein the selected section and the second section are vertically displaced within a single relatively permeable formation.
 7192. The method of claim 7171, wherein the selected section and the second section are substantially adjacent within a single relatively permeable formation.
 7193. The method of claim 7171, wherein the blending agent is injected into a production well in the second section, and wherein the mixture is produced in the production well.
 7194. The method of claim 7171, further comprising producing the mixture from the second section.
 7195. The method of claim 7171, further comprising producing the blending agent when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7196. The method of claim 7171, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7197. The method of claim 7171, wherein one or more of the heat sources comprise heaters.
 7198. The method of claim 7171, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 7199. A method for treating a relatively permeable formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the relatively permeable formation; allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat reduces the viscosity of at least some hydrocarbons within the selected section; producing the mixture from the selected section; and adjusting a parameter for producing the desired mixture based on at least one price characteristic of the desired mixture.
 7200. The method of claim 7199, further comprising allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section.
 7201. The method of claim 7199, wherein adjusting the parameter comprises selecting a location in the selected section for production of the mixture based on at least one price characteristic of the mixture.
 7202. The method of claim 7199, wherein adjusting the parameter comprises selecting a production location in the selected section to produce a selected API gravity in the produced mixture.
 7203. The method of claim 7199, wherein at least one price characteristic is determined by multiplying a production rate of the produced mixture at a selected API gravity from the selected section by a price obtainable for selling the produced mixture with the selected API gravity.
 7204. The method of claim 7199, wherein adjusting the parameter comprises controlling at least one operating condition in the selected section.
 7205. The method of claim 7204, wherein controlling at least one operating condition comprises controlling heat output from at least one of the heat sources.
 7206. The method of claim 7205, wherein controlling the heat output from at least one of the heat sources controls a heating rate in the selected section.
 7207. The method of claim 7204, wherein controlling at least one operating condition comprises controlling a pressure in the selected section.
 7208. The method of claim 7199, wherein at least one price characteristic comprises a characteristic based on a selling price for sulfur produced from the formation.
 7209. The method of claim 7199, wherein at least one price characteristic comprises a characteristic based on a selling price for metal produced from the formation.
 7210. The method of claim 7199, wherein at least one price characteristic comprises a characteristic based on a ratio of paraffins to aromatics in the mixture.
 7211. The method of claim 7199, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.
 7212. The method of claim 7199, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.
 7213. The method of claim 7199, wherein one or more of the heat sources comprise heaters.
 7214. The method of claim 7199, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about
 5. 7215. The method of claim 7199, wherein the produced mixture comprises an acid number less than about
 1. 